Exhibit 99.1
1 Brigham Exploration Company Shareholder Meeting May 28, 2009 |
Forward Looking Statements Except for the historical information contained herein, the matters discussed in this presentation are forward-looking statements that are based upon current expectations. 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 Regarding Hydrocarbon Disclosure 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, potential proved reserves or other potential reserves, resources or other estimates of hydrocarbon volumes, as well as probable drilling locations, that the SEC's guidelines prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are substantially less certain and no discount or other adjustment is included in the presentation of such numbers. In addition, our estimates of probable reserves may not meet the proposed definitions for such terms under the SEC's proposed revised oil and gas disclosure rules. In this communication, the term "potential" refers to the Company's internal estimates of hydrocarbon volumes that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. These potential hydrocarbon volumes may not constitute reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System or the SEC's proposed revised oil and gas disclosure rules and such volumes do not include proved reserves. Potential estimates have not been risked by Company management. Actual quantities that may be ultimately recovered from the Company's interests will differ substantially. Factors affecting ultimate recovery include the scope of our ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of hydrocarbon potential may change significantly as development of the Company's resource plays and prospects provide additional data. Unless otherwise indicated, estimates of probable reserves and other non-proved estimates of hydrocarbon volumes contained herein have been prepared internally by the Company without review by independent petroleum engineers. Investors are urged to consider closely the reserves disclosures in our Annual Report on Form 10-K for the year ended December 31, 2008. |
4 Corporate Overview |
Investment Highlights Disciplined, drill-bit focused producer with unique, oil-levered resource play potential Premier oil resource play in the United States Minimizes risk of gas on gas competition amongst Haynesville, Barnett and Marcellus Shales Over 300,000 net acres in the Williston Basin with Bakken, Three Forks and Red River potential Most leveraged (acreage to market cap) public company in the Williston Basin Significant portion of acreage acquired in last 18 months under 5 year leases Bakken recoveries continue to improve - enhancing EURs, production and returns Well by well improvement driving increased production rates and per well EURs Brigham is first operator in basin to successfully complete 20 stage stimulation Others in basin now applying same technology to drive economic gains Macro improvements make Williston Basin development highly economic Current drilling and completion costs reduced 30% relative to year-end Oil prices have experienced significant rebound in pricing since year-end Substantial reduction in differentials from $18 at year end to $7.50 per barrel in April Equity offering funds both increased Williston Basin activity as well as borrowing base redetermination Complete 3 operated wells started in 4Q08 with 20+ frac stages; participate in 15 non-operated wells in Parshall / Austin / Sanish in 2Q09; add incremental operated rig to further delineate resource base $35 million of proceeds will be used to repay redetermined borrowing base |
Liquidity Update / Financial Strategy Spring 2009 credit facility redetermination / amendment process complete BEXP focused on judicious use of capital to generate reserve / NAV per share growth 3 Bakken / Three Forks wells awaiting completion and provide immediate catalyst 2009 / 2010 capital program further delineates resource base Capital productivity enhanced given significant lease term remaining on vast majority of leases Significant natural gas hedges through 2009 70% of estimated natural gas production (based on 29MMcfe/d) hedged at $4.82 floor Opportunistically hedge oil volumes - currently 16% hedged (29 MMcfe/d) at $51.77 floor Additional optionality remains through multiple funding sources: Creation of Williston Basin JVs in Extensional Areas JVs / sale of conventional assets |
Core Operating Areas SOUTH TEXAS Vicksburg Trend Net Acreage: 3,891 Ac. 3-D Seismic: 806 Sq. Mi. 2008YE Reserves: 56.4 Bcfe 2008YE Production: 9.7 MMcfe/d 2009 Q1 Production: 7.1 MMcfe/d 9 Major Field Discoveries TOTAL COMPANY Net Acreage: 425,368 Ac. 3-D Seismic: 12,924 Sq. Mi. 2008YE Reserves: 137.1 Bcfe % Natural Gas: 69% 2008 Production: 31.8 MMcfe/d 2009Q1 Production: 32.0 MMcfe/d Reserves / Acreage as of 12/31/08 except Williston Basin acreage at current levels; Production average daily for 2008 WILLISTON BASIN North Dakota / Montana Net Acreage: 307,474 Ac. 3-D Seismic: 1,216 Sq. Mi. 2008YE Reserves: 23.4 Bcfe 2008 Production: 4.9 MMcfe/d 2009Q1 Production: 7.8 MMcfe/d |
High Potential Acreage Position in Williston Basin Bakken / Three Forks Play ~ 100,200 net acres in Mountrail County and Extensional Areas Potentially provides 156 net Bakken drilling locations assuming 2 laterals per 1280 acre spacing unit Potentially another 156 net Three Forks drilling locations assuming 2 laterals per 1280 acre spacing unit Additional ~105,800 net acres in Williams and McKenzie Counties, North Dakota Acreage includes Mrachek (McKenzie Co.) and Olson (Williams Co.) discoveries Potentially provides 165 net locations assuming 2 laterals per 1280 acre spacing unit, also with Three Forks potential Additional ~101,400 net acres in Eastern Montana in Roosevelt and Sheridan Counties Peer group comprised of Continental, EOG, Newfield, Northern Oil & Gas, St. Mary, Whiting and XTO BEXP Market capitalizations as of May 13, 2009 BEXP market capitalization based on May 13th close and pro forma shares of 78.7 million BEXP market capitalization based on May 13th close and pro forma shares of 78.7 million BEXP market capitalization based on May 13th close and pro forma shares of 78.7 million |
BEXP Assets Undervalued in Market |
Williston Basin Overview Carkuff 22 #1H - IP 1,110 Bopd |
Nesson Anticline Williston Basin Historical Overview Multiple Objective Potential - ~ 307,474 Net Acres BEXP Red River Discoveries Bakken Elm Coulee Field (Richland County, MT) discovered 2001 3 years later declared economic BEXP drilled 3 Bakken wells in Williams / McKenzie Co's, ND in 2006 ~105,800 Net Acres in those counties Field / Erickson wells IP @ ~ 200 Bopd, subsequently stabilized at 50 - 90 Bopd, est. avg. EUR 100-165 MBoe Three consecutive BEXP Red River discoveries in Sheridan Co, MT utilizing 3-D seismic 16 prospects & leads identified Prospecting for Red River, Bakken, Three Forks, Mission Canyon & other potential objectives on ~101,400 net acres Currently approximately ~100,200 net acres in Mountrail County, ND and extensional areas Numerous high rate completions BEXP 8 consecutive operated discoveries Plan to complete two long laterals with 20 frac stages BEXP Mrachek re-entry commenced at initial peak rate of 727 Boepd after stimulating 7 intervals Olson completed - initial rate 1,200 Bopd Figaro awaiting completion Recent strong Three Forks discoveries geographically dispersed around BEXP's Mountrail area acreage Second reservoir immediately below lower Bakken Shale BEXP's first Three Forks well successful with initial rate of ~892 Boed Completing first long lateral Three Forks test with ~20 planned frac stages Continental Three Forks Discoveries Key Three Forks Wells Encore & Fidelity Three Forks Discoveries BEXP Three Forks Tests BEXP 892 Boe/d Three Forks Discovery Whiting Three Forks Discovery Recent Whiting Three Forks Discovery BEXP Mrachek Discovery BEXP Olson Discovery |
Operational Evolution -- Drives Improving Economics EUR Est. Finding Cost 24 Stages 720 MBOE $11.79/bbl 20 Stages 630 MBOE $13.01/bbl 12 Stages 411 MBOE $14.70/bbl 7 Stages 236 MBOE $23.21/bbl Single Stage 127 MBOE $37.40/bbl |
Williston Basin Historical Overview Key Operated Wells Thru 2008 2008 BEXP Adix 22-1H Three Forks 11 Fracs 892 Boepd 2009 Wells BEXP Operated BEXP Non Op. 2008 BEXP Carkuff 22-1H 12 Fracs 1,110 Bopd OVER 1,500 HORIZONTAL BAKKEN PRODUCERS HAVE BEEN DRILLED IN THE WILLISTON BASIN TO DATE |
Williston Basin Three Forks Drilling 110 2009 BEXP Strobeck Three Forks 20 Frac Compl'n June 2009 Whiting Three Forks 10 Frac Stages Three Forks Initial Rate or IP NA NA 435 1,126 100 NA 87 100 1,005 NA 892 634 300 423 355 462 861 729 443 2,084 889 543 985 1,001 185 110 NA NA 1,417 272 1,080 297 178 265 Emerging 2ND Resource Play 75' to 150' Below the Middle Bakken 2009 BEXP Olson Core with Oil Saturated Three Forks 71 Three Forks Wells To Date 40 Producers 11 Completing 2 Drilling 18 Permits 2008 BEXP Adix Three Forks 11 Fracs - 432 Mboe 2009 BEXP Anderson Core with Top 30" of Oil Saturated Three Forks |
BEXP Rate vs. Cumulative Oil Plot 12 Frac Stage Adix Three Forks Well on Pump 12 Frac Stage Carkuff Well 20 Frac Stage Olson Rough Rider Well 10 Frac Stage Johnson Well |
Sequential Operational Improvement (Source RBC Capital Markets) Brigham has experienced sequential improvement in well results since initiating program late 2007 Second only to WLL in highest average IP in 1Q 2009 Represents Olson 10-15 #1H, which was completed with 20 fracture stimulation stages |
Completion Technology Drives Significant Production Increases & Improved Economics |
Total Well Cost (3) ~EUR, BO F&D Cost$/BOE Late 2009 9,500' Lateral, 1 Frac Stage $3,800,000 127,000 bbls $37.40/BOE 2006 2007 Late 2008 Early 2009 5,000' Lateral, 7 Frac Stages, 715'/interval 236,000 bbls $4,383,000 $23.21/BOE 9,500' Lateral, 20 Frac Stages, 475'/interval $6,559,000 630,000 bbls $13.01/BOE Pre-Swell Packers Early Swell Packers More Fracs/Smaller Frac Intervals Long Lateral/More Frac Intervals More Fracs/Smaller Frac Intervals 1) BEXP estimated EUR for Olson 20 frac stage long lateral. 2) BEXP estimate calculated based on frac stage versus EUR best line fit, given that no wells have been completed to date with 24 frac stages. 3) Utilizing current well cost estimates. (1) (2) Single Frac Stimulation Cost ~$100,000 Incremental Fracs Generating ~35,000 Bo/Frac Cost/Barrel Per Frac Stimulation ~ $2.71/Boe Operational Advancements Drive Improved Bakken/Three Forks Well Performance & Economics |
Bakken/Three Forks Drilling Capex ($Millions) $5.1 $11.8 $18.2 $26.7 Laid Down Operated Rigs 1 Rig 1 Rig 2 Rigs 2 Rigs Figaro, Strobeck & Anderson (20,20 & 24 Frac Stage Wells) Should Be Fracture Stimulated Q3 Expect to Resume Operated Drilling Mid-Year Olson Carkuff Adix Wayzetta 13-1H Mrachek Austin 25-35H Johnson Q1 2009 Williston Oil Production 2.7 X Q1 2008 Mboe/d Growing Bakken / Three Forks Oil Production Growth in High Value Long Life Production Bakke 7 Fracs 144 MBOE Mrachek 7 Fracs 215 MBOE Adix 11 Fracs Three Forks 432 MBOE Olson 20 Fracs ~630 MBOE Carkuff 12 Fracs (curtailed for few months) 411 MBOE Johnson 10 Fracs 310 MBOE EOG Curtailment 2007 2008 2009 2006 Field & Erickson Single Fracs ~115 MBOE Avg. |
Rough Rider Area Olson ~EUR 630 MBOE Short Lateral (640) vs. Long Lateral (1280) Capex / F&D Costs DECLINING DRILLING COSTS DRIVE DOWN F&D COSTS/BOE $6.1 $4.8 $4.2 $ millions $9.5 $6.6 $5.6 $ millions 20-30% 31-42% Ross Area Carkuff ~ EUR 411 MBOE 10% 20% 30% 40% 0% 40% ROR 21% 32% *NYMEX Strip 5/6/09 20% 80% 0% 80% 29% 56% ROR 40% 60% July 1, 2009 completion costs based on Company estimates. Olson EUR based on BEXP's internal estimates. |
Significant Reserve Opportunity / Optionality |
Bakken/Three Forks Bakken/TF Probable Vicksburg Vicksburg Probable Other Other Probable A 10 35 23 2 22 8 Year End 2008 Proved & Probable Reserves* Substantial Probable Reserves * Based on independent engineering by Cawley, Gillespie & Associates, Inc. at December 31, 2008. 2P Total 249 Bcfe (41.5 MMboe) Proved Bcfe Probable Bcfe Bakken/Three Forks 23.5 87.2 Vicksburg 56.4 5.8 Hunton 16.9 2.4 Other 13.2 6.0 Frio 10.4 6.5 Springer Bar/Ch 6.4 2.5 HA Trend 5.0 1.5 S. Louisiana 5.2 Totals 137 112 |
Williams Co., ND Year End 2008 Reserves Based on 2008 SEC Guidelines 2006 BEXP Erickson Well Single Uncontrolled Frac 2006 BEXP Field Well Single Uncontrolled Frac 2008/9 BEXP Olson Well 20 Stage Frac - Initial Rate 1,200 Bo & 1.4 Mmcfg per day PUDs Only Booked to Adjacent Reserve Levels -- Could Not Assume Performance Associated with Higher Number of Frac Stages X Unbooked, Uneconomic PUDs due to YE08 Prices & Offsetting EURs 540 MBOE Proved 64 MBoe Proven Remaining 50 MBoe Proven Remaining |
64 MBoe Proven Remaining 50 MBoe Proven Remaining 2008/9 BEXP Olson Well 20 Stage Frac - Initial Rate 1,200 Bo & 1.4 Mmcfg per day 2006 BEXP Field Well Single Uncontrolled Frac 2006 BEXP Erickson Well Single Uncontrolled Frac Proposed YE09 SEC Rules May Allow 8 Direct Offset PUDs Booked at Reserve Levels of Higher Frac Stage Wells Williams Co., ND Year End 2008 Reserves Based on Proposed 2009 SEC Guidelines * Olson EUR based on BEXP's internal estimates. *Subject to reservoir continuity, geologic control, and final adoption and interpreation of new SEC rules for YE09. No assurance additional PUD wells will be booked at YE 09. |
PD PUD Probable Bakken Potential Three Forks Potential Ross Area 0.7 1 6.9 5.2 13.8 Bakken/Three Forks Reserves Potential By Category & Area (1 Bakken / 1 Three Forks Well per Section) PD PUD Probable Bakken Potential Three Forks Potential Rough Rider Area 0.4 0.8 6.7 39.5 49.8 PD PUD Probable Bakken Potential Three Forks Potential Parshall/Austin Area 0.6 0.4 0.9 5.9 7.7 PD PUD Probable Bakken Potential Three Forks Potential Williston Total 1.7 2.2 14.5 130.7 144.8 27.6 MMboe 97.2 MMboe 15.5 MMboe 293.9 MMboe *Includes Montana Acreage & Extensional Areas |
2009 - 2010 Development Plan |
Williston Basin Bakken & Three Forks Resource Drilling Key Operated Wells Thru 2008 Anticipated 2009 Wells Only 2008 BEXP Adix 22-1H Three Forks 11 Fracs 892 Boepd 2009 Wells 2008 Proved Sections ~ 4 MMboe or 23.5 Bcfe 2009 BEXP Figaro 20 Fracs Compl'n July Currently 16 2009 Non Operated Wells BEXP Operated BEXP Non Op. 2009 BEXP Strobeck Three Forks 20 Frac Compl'n June 2008 BEXP Carkuff 22-1H 12 Fracs 1,110 Bopd 2009 BEXP Anderson 24 Fracs Compl'n June OVER 1,500 HORIZONTAL BAKKEN PRODUCERS HAVE BEEN DRILLED IN THE WILLISTON BASIN TO DATE |
Williston Basin Bakken & Three Forks Resource Drilling Anticipated 2009 and 2010 Operated Wells (Non Op. Not Incl.) 2009 Wells 2008 Proved Sections ~ 4 MMboe or 23.8 Bcfe 2010 Wells 2010 Operated Well #3 2010 Operated Well #5 2010 Operated Well #6 2010 Operated Well #7 2010 Operated Well #8 2010 Operated Well #10 2010 Operated Well #9 2010 Operated Well #4 (1) |
Williston Basin Three Forks Drilling 2008 Proved Sections 521 Mboe or 3.1 Bcfe 2010 Operated Well #5 2010 Operated Well #6 2010 Operated Well #7 2010 Operated Well #8 2010 Operated Well #10 110 2010 Operated Well #3 2010 Operated Well #9 2009 BEXP Strobeck Three Forks 20 Frac Compl'n June 2009 Whiting Three Forks 10 Frac Stages Three Forks Initial Rate or IP NA NA 435 1,126 100 NA 87 100 1,005 NA 892 634 300 423 355 462 861 729 443 2,084 889 543 985 1,001 185 110 NA NA 1,417 272 1,080 297 178 265 Emerging 2nd Resource Play 75' to 150' Below the Middle Bakken 2009 BEXP Olson Core with Oil Saturated Three Forks 71 Three Forks Wells To Date 40 Producers 11 Completing 2 Drilling 18 Permits 2009 BEXP Anderson Core with Top 30" of Oil Saturated Three Forks 2010 Operated Well #4 (1) |
Williston Basin Bakken & Three Forks Resource Drilling Approximate # of Initial Wells in Each Proration Unit Rough Rider ~205 Wells Parshall Austin Sannish ~43 Wells Ross ~125 Wells Ross ~250 Wells NW Ross ~47 Wells S. Parshall ~17 Wells Approximately 462 Initial Potential Locations Per Production Unit in Best Delineated Areas NW Ross ~22 Wells |
Williston Oil Marketing |
Brigham's Oil Differential to NYMEX Average By County Footnote: Arithmetic Average by Purchaser by County Williams, ND McKenzie, ND Mountrail, ND REASONS FOR NORMAL WIDENING OF DIFFERENTIALS IN WINTER Less demand for gasoline as the driving season ends in September Refiners run more sour and synthetic oil, which yields a higher percentage of heavy distillates With limited pipeline take-away capacity, local sweet production is vulnerable to increasing differentials REASONS FOR INCREASED WIDENING DIFFERENTIALS IN ND DURING WINTER 2008 Primarily attributed to national refining economics and regional pipeline take-away capacity Refining margins, as determined by the "crack spread," are negative Demand for refined products is down resulting in increased inventory and lower prices The combined value of gasoline and heating oil is less than that of crude Margins on other products have kept refiners barely profitable Lack of pipeline capacity out of the Williston Basin continues Enbridge and Platte pipelines remain prorated Approximately 20,000 to 25,000 BOPD being moved by rail SUMMARY As long as refining economics remain poor, refiners must pay a discount to the NYMEX for oil, regardless of its absolute value The result is a widening of the differentials As refining economics return to a more normal conditions, differentials should narrow |
Brigham's Oil Differential to NYMEX Weighted Average for Basin |
Oil Pipelines and Refineries Keystone Pipeline Enbridge Pipeline Oil Refineries Oil Pipelines Platte Pipeline Butte Pipeline 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 White Cliffs Pipeline Suncor 88,000 Stanley, ND Railcar Loading To Houston Clearbrook, MN Proposed Keystone Expansion Portal Reversal State of ND Proposed Keystone Connection Ross, ND |
Vicksburg Overview |
Formed first JV with ExxonMobil in 1997 4 additional JVs implemented Natural gas play targeting numerous over pressured sands Since 1999, 42 completions in 45 attempts In 2008, completed all 3 100% initial WI wells Anticipate 2009 wells at initial 100% WI 53 drilling locations at year-end 2008 35 proved, 10 probable and 8 possible All acreage held by production (HBP) Can selectively drill wells depending upon natural gas prices and service costs ExxonMobil Vicksburg Joint Venture Brooks County, South Texas PUD Probable Home Run Field Triple Crowne Field Floyd Field Floyd South Field Possible PDP 2009 Planned Well - Sullivan #10 |
2 3 4 5 6 7 8 9 $6 MM WELL COST 0 11 29 54 88 130 180 240 $3.9 MM WELL COST 10.41 42 92 150 220 Vicksburg is an Excellent Cash Flow Generator Operational Enhancements Dramatically Impacting Well Economics Relative to Gas Prices & Rates of Return - 2.8 BCFE EUR *Assumed 2.8 Bcfe Vicksburg well as blended average for Triple Crown, Home Run and Floyd Fields. CWC $3,900M for 12,500' Vicksburg; OPEX at $6,189/mo; Differentials: -$0.545/Bbl and 1.417 Gas price factor |
DECLINING DRILLING COSTS DRIVE DOWN F&D COSTS/MCFE $ millions 35-40% *NYMEX Strip 5/6/09. Assumed 2.8 Bcfe Vicksburg well as blended average for Triple Crown, Home Run and Floyd Fields. 2.8 BCFE EUR VICKSBURG 70% >100% >100% 20% ROR 40% 80% 60% 0% ExxonMobil Vicksburg Joint Venture Capex / F&D Costs *July 1, 2009 completion costs based on Company estimates 2009 Planned Well: Est. Cost Est. Rate Est. Payout Est. ROR Sullivan #10 Floyd Repl. $4.7 million 3.0 MMcfed 12 Months >100% |
Key Takeaways Equity transaction accomplishes the following: Provides capital to rapidly bring on line 3 impactful Bakken / Three Forks wells Further, provides funding for 13 gross operated wells drilled over 18 months without additional capital Provides capital to continue to fund escalating non-operated drilling in Parshall / Austin / Sanish areas Provides capital to address near term acreage expirations via drilling and extensions Addresses impact of borrowing base redetermination Environment - positive oil price movement, reduced service costs, reduced differentials, natural gas oversupply - all coming together to create favorable oil resource play operating environment Given our size, most impactful acreage position in Williston Basin Favorable current terms and minimal expenditures enable us to retain bulk of acreage Brigham completion designs driving superior sequential production and reserve performance Significant Williston Basin optionality with multiple objectives, infill drilling and continued evolution in completion design to drive reserve and production growth |