Williston Basin Petroleum Conference Advances in Technology Panel Efficient Fracture Stimulation Rick Ross – Whiting Petroleum Corporation 1

Forward-Looking Statement Disclosure This presentation includes forward-looking statements that the Company believes to be forward- looking statements within the meaning of the Private Securities Litigation Reform Act of All statements other than statements of historical fact included in this presentation are forward- looking statements. These forward looking statements are subject to risks, uncertainties, assumptions and other factors, many of which are beyond the control of the Company. Important factors that could cause actual results to differ materially from those expressed or implied by the forward-looking statements include the Company’s business strategy, financial strategy, oil and natural gas prices, production, reserves and resources, impacts from the global recession and tight credit markets, the impacts of hedging on our results of operations, level of success in exploitation, exploration, development and production activities, uncertainty regarding the Company’s future operating results and plans, objectives, expectations and intentions and other factors described in the Company’s most recent Annual Report on Form 10K. In addition, Whiting’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. 2

Outline Completion objectives and methods utilized Evolution of completion tools, current state and future Strategies for full field development Flow back practices Cost control Whiting performance Summary 3

Completion Objectives Maximize Stimulated Reservoir Volume –Good distribution of stimulation across the lateral Optimize cost, performance, and logistics of stimulation strategies utilized –Fluids –Diversion –Proppant –Pressure pumping service availability 4

Horizontal Wellbore Configuration Packer Assembly Run to ~ 10,000’ Lateral Distance 7” Casing 4 ½” Liner with Swelling Packers & Sliding Sleeves 4 ½” Liner with Swelling Packers & Sliding Sleeves ~10,000’ Vertical Vertical Courtesy of Baker Hughes Inc ’ 5

Evolution of Sleeve Systems First sleeve system was utilized in Sanish field in December 2007 – (8 stages) Expanded number of stages up to 24 – Nov 2009 Hybrid systems to achieved 30 stages– but inefficient & costly First 30 stage sleeve system (1/16” increments) Feb 2011 Development of 40 stage system. – March 2011 –“Standard” long lateral is 30 stages Multi port systems – field tested in several Sanish wells 6

Evolution of Sleeve Systems Future? 7

Current Completion Strategy Utilize oil swelling packers and sliding sleeve system (ball actuated). –Number of stages utilized based on rock properties and area performance. –Use a 30 stage sleeve system with “long lateral”. Approximate Job Volumes for a 30 Stage System: MM# total proppant Small mesh sand for fluid loss 20/40 mesh natural sand for main stages 25,000 – 30,000 bbls water 8

Benefits of Sliding Sleeves Optimize utilization of frac crew – 30 stage job frac is less than 24 hrs. Lower completion cost. –Lower frac ticket cost due to efficiency of operations –No “drill out” required Advantage in winter operations. Less load water – gun pump downs, flush volume. 9

Considerations for Full Field Development Early development generally focused on holding acreage and delineation of acreage. Especially where both Bakken and Three Forks are prospective, potential for communication exists. Areal conformance important 10

Fully Developed Bakken and Three Forks Horizontal Wells in Sanish Field Area 11

Best Practices: Post Frac – Flow Back Techniques Complete construction of battery and if possible gas connection prior to stimulation. Lateral Section clean-up during flow back –Pressure differential allows balls in the toe section to come off seat. –Flow back on a 48/64 th choke for 6-8 hours, and then run “IP test” after the well reaches 50% oil cut. –Have run tracers in frac stages to understand individual zone contribution during flow back. –Clean out of lateral is usually not warranted – but exceptions. 12

Best Practices: Post Frac – Flow Back Techniques 13

Best Practices: Post Frac – Flow back Techniques Question – Are the frac balls recovered during flow back? Answer - A recent 30 stage completion flowed back 30 of 30 14

Controlling Well Costs Upward Pressure Dedicated service contracts Diesel costs (fuel surcharges) Sand price increases Potential Guar shortage Overall upward movement in services and equipment Downward Pressure Reduction in drilling time Pad drilling/ common facilities Efficient completions with sleeve systems Reduction in cycle time Dedicated frac crews - scheduling Increased services 15

16 Bakken Wells in North Dakota Completed after 1/1/2008 with 6 Months Production – 1817 Wells Source: NDIC website

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Questions? Contact Information: Rick Ross (303)

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General Bakken Formation Data Reservoir and Fluid Properties –Depth: ~10,000’ –Bottom Hole Temperature: 210 F –Reservoir Pressure: 5,000 – 7,000 psig –Pressure Gradient: 0.5 – 0.7 psi/ft –Bubble Point: 1,800 – 3,000 psig –Solution GOR: 500-1,500 scf/bbl –Permeability: – 1 md –Frac Gradient: 0.76 – 0.85 psi/ft Middle Bakken Core - Sanish Field 20

Bakken Regional Setting Modified after Meissner, 1983 & Peterson and MacCary, 1987

23 Three Forks Wells in North Dakota Completed after 1/1/2008 with 6 Months Production – 497 Wells Source: NDIC website