Wll june 2013

Whiting Petroleum Corporation Current Corporate Presentation June 2013

2

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 1995. 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 state and federal laws, 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 Annual Report on Form 10-K for the year ended December 31, 2012. 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. In this presentation, we refer to Adjusted Net Income and Discretionary Cash Flow, which are non-GAAP measures that the Company believes are helpful in evaluating the performance of its business. A reconciliation of Adjusted Net Income and Discretionary Cash Flow to the relevant GAAP measures can be found at the end of the presentation. Whiting uses in this presentation the terms proved, probable and possible reserves. Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods

and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Probable reserves are reserves that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are reserves that are less certain to be recovered than probable reserves. Estimates of probable and possible reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company. Whiting uses in this presentation the term “total resources,” which consists of contingent and prospective resources, which SEC rules prohibit in filings of U.S. registrants. Contingent resources are resources that are potentially recoverable but not yet considered mature enough for commercial development due to technological or business hurdles. For contingent resources to move into the reserves category, the key conditions, or contingencies, that prevented commercial development must be clarified and removed. Prospective resources are estimated volumes associated with undiscovered accumulations. These represent quantities of petroleum which are estimated to be potentially recoverable from oil and gas deposits identified on the basis of indirect evidence but which have not yet been drilled. This class represents a higher risk than contingent resources since the risk of discovery is also added. For prospective resources to become classified as contingent resources, hydrocarbons must be discovered, the accumulations must be further evaluated and an estimate of quantities that would be recoverable under appropriate development projects prepared. Estimates of resources are by nature more uncertain than reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company.

Forward Looking Statements, Non-GAAP Measures, Reserve and Resource Information

(1) Whiting reserves at December 31, 2012 based on independent engineering.

(2) R/P ratio based on year-end 2012 proved reserves and 2012 production.

Q1 2013 Production 89.1 MBOE/d

Proved Reserves(1) 378.8 MMBOE

% Oil 80%

R/P ratio(2) 13 years

3

Whiting Overview

Drilling on the Hidden Bench Prospect in McKenzie County, North Dakota.

ROCKY MOUNTAINS

66.1 MBOE/D

PERMIAN

11.3 MBOE/D

MID-CONTINENT

7.9 MBOE/D

MICHIGAN

2.6 MBOE/D

GULF COAST

1.2 MBOE/D

Q1 2013 Net Production

89.1 MBOE/d

4

Map of Operations

74%

13%

9% 3% 1%

Rockies Permian

Mid-Con Michigan

Gulf Coast

378.8 MMBOE Proved Reserves(1) (12/31/2012)

(1) Whiting reserves at December 31, 2012 based on independent engineering.

5

51%

33%

13% 2% 1%

Rocky Mountains Permian Basin Mid-Continent

Michigan Gulf Coast

Platform for Continued Growth 80% Oil / 10% NGL / 10% Natural Gas

3P Reserves (1)

Oil (MMBbl)

NGLs (MMBbl)

Natural Gas (Bcf)

Total (MMBOE)

% Oil

Pre-Tax PV10% Value

(In MM) % Total

Proved 301.3 40.1 224.3 378.8 80% $7,284(2) 73%

Probable 85.0 11.9 109.6 115.2 74% $1,262(3) 13%

Possible 123.2 21.9 156.4 171.2 72% $1,359(3) 14%

(1) Oil and gas reserve quantities and related discounted future net cash flows have been derived from oil and gas prices calculated using an average of the first-day-of-the month NYMEX price for each

month within the 12 months ended December 31, 2012, pursuant to current SEC and FASB guidelines. The NYMEX prices used were $94.71/Bbl and $2.76/MMBtu.

(2) Pre-tax PV10% of Proved reserves may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the

most directly comparable US GAAP financial measure. Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future

income taxes. As of December 31, 2012, our discounted future income taxes were $1,876.9 million and our standardized measure of after-tax discounted future net cash flows was $5,407.0 million. We

believe pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our pre-tax PV10%

as a basis for comparison of the relative size and value of our proved reserves to other companies because many factors that are unique to each individual company impact the amount of future income

taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our oil and gas properties and acquisitions. However, pre-tax PV10% is not a

substitute for the standardized measure of discounted future net cash flows. Our pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair

value of our proved oil and natural gas reserves.

(3) Pre-tax PV10% of probable or possible reserves represent the present value of estimated future revenues to be generated from the production of probable or possible reserves, calculated net of

estimated lease operating expenses, production taxes and future development costs, using costs as of the date of estimation without future escalation and using 12-month average prices, without giving

effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or future income taxes and discounted using an annual

discount rate of 10%. With respect to pre-tax PV10% amounts for probable or possible reserves, there do not exist any directly comparable US GAAP measures, and such amounts do not purport to

present the fair value of our probable and possible reserves.

6

Whiting Pre-Tax PV10% Values at December 31, 2012 Using SEC NYMEX of $94.71/Bbl and $2.76/Mcf Held Flat

(1)These multi-year CO2 projects involve many re-entries, workovers and conversions. Therefore, they are budgeted on a project basis not a well basis. (2)Comprised of exploration salaries, seismic activities, delay rentals and exploratory drilling.

7

Northern Rockies

1,142 MM

EOR 240 MM

Central Rockies 136 MM

Non-Operated 164 MM

Land 108 MM

Exploration Expense (2)

82 MM

Facilities 178 MM

Well Work, Misc. Costs,

Other 150 MM

EST. 2013 CAPEX IN

MM % Gross Wells

Net Wells

Northern Rockies $1,142 52% 219 148

EOR 240 11% NA(1) NA(1)

Central Rockies 136 6% 37 27

Non-Operated 164 7%

Land 108 5%

Exploration Expense (2) 82 4%

Facilities 178 8%

Well Work, Misc. Costs, Other 150 7%

Total Budget $2,200 100% 256 175

Capital Budget for Key Development Areas in 2013 ($ in millions)

8

Drilling Inventory

Identified Primary Locations

Northern Rockies Gross Net Wells per Spacing Unit

Southern Williston (Lewis & Clark; Pronghorn) 1,104 410.2 3 Pronghorn Sand / 1280

Western Williston(1) (Cassandra; Hidden Bench; Tarpon; Missouri Breaks) 1,174 380.5 4 Middle BKN; 3 Upper TFK / 1280

Sanish (Sanish; Parshall) (2) 260 118.1 3.5 Middle BKN; 3 Upper TFK / 1280

Other (3) 588 340.3

Total 3,126 1,249.1

Central Rockies

Redtail Niobrara 2,420 1,215.7 8 Nio "B"; 4 Nio "A" / 640 - 960

Other (4) 958 654.1

Total 3,378 1,869.8

Gulf Coast 131 98.1 Mid-Cont 41 33.7

Permian Basin (5) 817 319.3

Michigan 63 53.3

Total Primary Inventory 7,556 3,623.3

Identified Prospective Locations

Williston Basin

Williston Basin New Objectives Gross Net Wells per Spacing Unit

Missouri Breaks Upper Three Forks 321 102.8 3 Upper TFK / 1280

Hidden Bench Lower Bakken Silt / Higher Density Pilot 556 161.9 4 BKN Silt; 4 Middle BKN per 1280

Cassandra Lower Three Forks 120 40.0 4 Lower TFK per 1280

Tarpon Lower Three Forks 40 15.0 3 Lower TFK per 1280

Total 1,037 319.7

Williston Basin Higher Density Locations

Pronghorn Sand Higher Density 453 167.3 3 Add'l Pronghorn Sand / 1280

Sanish Higher Density and Infill 191 175.9 3 Add'l Middle BKN / 1280

Total 644 343.2

Williston Basin Total Prospective Locations 1,681 662.9

Permian Basin

Big Tex Horizontal 424 217.0 6 Upper Wolfcamp / 640

Total Prospective Inventory 2,105 879.9

Total Potential Locations (6) 9,661 4,503.2

(1) Tarpon primary development on 3 Middle BKN; 2 Upper TKS due to high natural fracturing. Excludes Upper TFK at Missouri Breaks. (2) Cross unit boundary wells at Sanish result in an average of 3.5 wells per spacing unit. Parshall was developed on 640-acre spacing units and there is no Three Forks. (3) Various fields in North Dakota and Montana, including Big Island, Starbuck, Big Stick and others. (4) Various fields in Colorado, Wyoming and Utah including Sulphur Creek, Fontenelle, Nitchie Gulch, Flat Rock and others. (5) Various fields in Texas and New Mexico including Jo-Mill, West Jo-Mill, Garza, Signal Peak and others. (6) Locations include both 3P reserves and Resource Potential.

B Zone Ф 4.4% to 6.1% K = .001 to .1 md So = 80% OOIP (MMBOE /1280 ac) = 7

Williston Basin (Bakken and Three Forks) Sanish Hydrocarbon System Stratigraphy

A Zone Ф 6.3% to 7.9% So = 75% OOIP (MMBOE /1280 ac) = 6

C Zone Ф 6.0% to 9.4% K = .005 to .01 md So = 78% OOIP (MMBOE /1280 ac) = 6

D Zone Ф 4.7% to 6.5% K = .003 md So = 75% OOIP (MMBOE /1280 ac) = 11

Three Forks Ф 7.0% K = .001 - .02 md So = 57.5% OOIP (MMBOE /1280 ac) = 9

A B C

D

9

Sanish Field Infill Resource Estimate

Middle Bakken

A Zone

B Zone

C Zone

D Zone

Total Middle Bakken

Total Bakken Shale**

Three Forks

Grand Total

OOIP by Zone

MMBOE/1280*

6

7

6

11

30

19

9

58

OOIP by Zone

10

4 wells

10% Recovery

(Current Design)

7 wells

15% Recovery

7 wells

20% Recovery

0.75 0.64 0.85

Middle Bakken Recoverable Oil per Well

(MMBOE)

* Assumes fieldwide average with constant GOR (1000 MCF/BO)

** Bakken Shale recovery efficiency is generally considered < 2%

11

Williston Basin Primary and Prospective

Drilling Plan by Area

(1) As of 3/31/13, Whiting’s total acreage cost in 704,525 net acres is approximately $371 million, or $526 per net acre.

12

MISSOURI BREAKS

LEWIS

& CLARK

CASSANDRA

BIG ISLAND

SANISH & PARSHALL

STARBUCK

HIDDEN BENCH

TARPON

Pronghorn

Sanish

Whiting Lease Areas in Williston Basin

(1)

Field Target

Gross

Acres

Net

Acres

Sanish / Parshall

Middle Bakken /

Three Forks 174,466 82,400

Pronghorn Pronghorn Sand 196,822 128,080

Lewis & Clark Three Forks 199,660 134,114

Hidden Bench

Middle Bakken /

Three Forks 47,958 28,832

Tarpon

Middle Bakken /


Starbuck

Middle Bakken /

Three Forks /

Red River 105,664 91,228

Missouri Breaks

Middle Bakken /


Cassandra

Middle Bakken /


Big Island Red River 176,900 125,530

Other ND & Montana 75,377 28,719

1,111,802 704,525

OBJECTIVE Pronghorn Sand 3 wells per 1,280-acre spacing unit

ACREAGE Whiting has assembled 396,482 gross (262,194 net) acres in our Southern Williston Basin. • Average WI of 66% • Average NRI of 53% • Well by well WI and NRI will vary based on ownership in each spacing unit

COMPLETED WELL COST Horizontal: $7.0 MM

DRILLING HIGHLIGHTS Plan to test a higher density pilot program at Pronghorn. Intend to drill six Pronghorn sand wells per 1,280-acre spacing unit, up from our initial plan of three wells per spacing unit.

13

LEWIS & CLARK

BIG ISLAND

Pronghorn

Southern Williston Basin Lewis & Clark and Pronghorn (March 31, 2013)

Planned Higher Density Pilot Locations

OBJECTIVE(1)

Bakken 4 wells per 1,280-acre spacing unit Three Forks 3 wells per 1,280-acre spacing unit

ACREAGE Whiting has assembled 182,913 gross (114,454 net) acres in our Western Williston Basin. • Average WI of 63% • Average NRI of 50% • Well by well WI and NRI will vary based on ownership in each spacing unit

COMPLETED WELL COST Horizontal: $7.0 MM to $8.5 MM

DRILLING HIGHLIGHTS Identified an additional reservoir (the “Middle Bakken Silt”) positioned between the Middle Bakken and Three Forks. Plan to test this zone by drilling 160 acre spaced wells above and below this target zone and stimulating these wells with large frac volumes. We believe that this higher density drilling could also improve our recovery efficiency in the Middle Bakken reservoir. (1) Tarpon primary development on 3 Middle BKN; 2 Upper TKS due to high natural fracturing. Excludes Upper TFK at Missouri Breaks.

14

STARBUCK

MISSOURI BREAKS

HIDDEN BENCH

CASSANDRA

TARPON

Western Williston Basin

Cassandra, Hidden Bench, Tarpon, and Missouri Breaks (March 31, 2013)


OBJECTIVE Bakken 3.5 wells per 1,280-acre spacing unit Three Forks 3 wells per 1,280-acre spacing unit

ACREAGE Whiting has assembled 174,466 gross (82,400 net) acres in our Sanish and Parshall fields. • Average WI of 47% • Average NRI of 39% • Well by well WI and NRI will vary based on ownership in each spacing unit

COMPLETED WELL COST Horizontal: $6.5 MM to $7.0 MM

DRILLING HIGHLIGHTS Plan a higher density pilot program in the Sanish field in the first half of 2013 that could add up to 3 additional Middle Bakken wells per 1,280-acre spacing unit. We also plan to refrac several wells at Sanish in 2013.

15

SANISH

PARSHALL

Sanish Area Sanish and Parshall Fields (March 31, 2013)


OBJECTIVE Vertical Red River

BIG ISLAND Whiting has assembled 176,900 gross (125,530 net) acres in our Big Island development project: • 11 of 12 successful completions to date. • Have identified over 50 prospects in the Upper Red River “D”. • Currently extending the prospect to the west into Wibaux County, MT.

STARBUCK Whiting has assembled 105,664 gross (91,228 net) acres and is currently interpreting a 283 square-mile 3-D seismic shoot designed to identify Red River drilling locations.

MISSOURI BREAKS Whiting has assembled 95,803 gross (65,481 net) acres at Missouri Breaks and planning a 3-D seismic survey in 2014.

ESTIMATED ULTIMATE RECOVERY 200 – 300 MBOE per well

COMPLETED WELL COST $3 MM - $3.5 MM

DRILLING PROGRAM At Big Island we recently completed the Stecker 32-9 producing 308 BOEPD and the Davidson 13-19 producing 226 BOEPD.

16

Red River Plays Sheridan, Roosevelt, Golden Valley and Wibaux Counties

EUR – 600 MBOE

EUR – 400 MBOE

EUR - 600 MBOE , Development Phase CAPEX $7.5 MM

Nymex oil price/Bbl $80 $90 $100

ROI 3.0 3.5 4.0

IRR (%) 93% 135% 189%

Payout (Yrs.) 1.2 0.9 0.8

PV(10) $MM 8.43 10.88 13.33

EUR - 400 MBOE , Development Phase CAPEX $7.5 MM

Nymex oil price/Bbl $80 $90 $100

ROI 1.9 2.2 2.6

IRR (%) 28% 41% 59%

Payout (Yrs.) 2.7 2.0 1.6

PV(10) $MM 2.78 4.42 6.07

Eq

uiv

ale

nt

Daily P

rod

ucti

on

BO

E/D

1,000

100

10

0 20 40 60 80 100 120 140 160 180

Months on Production

(1) Please refer to the beginning of this presentation for disclosures regarding "Reserve and Resource Information." All volumes shown are un-risked. Our pre-tax PV10% values do not purport to present the fair value of our oil and natural gas reserves.

(2) EURs, ROIs, IRRs and PV10% values will vary well to well. Estimates updated as of December 31, 2012.

17

Williston Basin Production Profile Range of Reserves: Bakken / Pronghorn Sand / Three Forks (1)(2)

555

472

419

655

524

428

-

100

200

300

400

500

600

700

30 Day 60 Day 90 Day

2012 Average 30, 60, 90 Day Rates (BOPD) Sanish Bakken and Three Forks vs. Pronghorn, Lewis & Clark and Hidden Bench

Sanish Bakken and Three Forks Pronghorn, Lewis & Clark and Hidden Bench

18

Productivity Increase with Shift to New Development Areas

(1) Production forecast is for visual demonstration purposes only and should not be considered accurate for any near or long term planning. Source: The North Dakota Pipeline Authority Presentation (2) Based on most up to date information from NDIC and Montana Board of Oil and Gas

19

NDPA Williston Basin Oil Production & Export Capacity (1)

BOPD

Feb 2013 Production

837,906 BOPD(2)

SANISH FIELD

Gathering System

Oil Gathering Lines 121 Miles

Gas Gathering Lines 363 Miles

Current Wells Connected (Op.) 313

Current Wells Connected (Non-Op.) 387

Total Current Wells Connected 700

Est. Ultimate Wells Connected 1,538

Robinson Lake Gas Plant

Volume (4/15/13) 69 MMcfd

Planned Capacity (1)

Processing 90 MMcfd

Compression 80 MMcfd

Fractionator 310 Mgpd

Capital Investment (2)

Oil Gathering/Terminal $25 MM

Gas Gathering 36 MM

Robinson Lake Gas Plant 72 MM

Total $133 MM

Estimated 2013 Annual Operating Cash Flow(2) $40 MM

(1) Planned capacity through 2013

(2) Values presented pertain to Whiting's 50% Ownership

20

Plants / Pipeline Williston Basin – Natural Gas Processing Plants (Robinson Lake)

Pronghorn Field

Planned Gathering System

Oil Gathering Lines 143 Miles

Gas Gathering Lines 137 Miles

Current Wells Connected (12/31/12 – Op.) 80

Current Wells Connected (12/31/12 – Non-Op.) 5

Total Current Wells Connected 85

Ultimate Wells Connected (Op & Non) 310

Belfield Gas Plant

Volume (4/15/13) 13 MMcfd

Planned Capacity (1)

Processing 30 MMcfd

Compression 24 MMcfd

Capital Investment (2)

Oil Gathering/Terminal $29 MM

Gas Gathering 23 MM

Belfield Gas Plant 34 MM

Total $86 MM

Estimated 2013 Annual Operating Cash Flow(2) $20 MM

(1) Planned capacity through 2013

(2) Capital Investment and Net Income pertain to 50% ownership

21

Plants / Pipeline Williston Basin – Natural Gas Processing Plants (Belfield)

Built

Planned

Built Planned

Niobrara Reservoir

Whiting RAZOR 25-2514H

GR Zone PHI Mineralogy BVFluid RES 0 200 30 -10 0 0.2 2000

10

A

B

C

Niobrara Resource Potential

*

**

GOR=500 cf/bo

Stimulated Rock Volume

22

Reservoir Porosity

(%)

Thickness

(ft)

OOIP

(MMBOE/960ac)*

NIO A 13% 35 19

NIO B 13% 65 40

NIO C 11% 25 11

59

OOIP by Zone

Total A Zone + B Zone**

16 wells

10% Recovery

16 wells

15% Recovery

16 wells

20% Recovery

0.37 0.55 0.74

Recoverable Oil per Well (MMBOE)

Redtail Resource Potential Niobrara A&B Reservoirs

OBJECTIVE Niobrara “B” Shale Niobrara “A” Shale

DEVELOPMENT PLAN Mix of 960 and 640-acre spacing units 8 Wells per spacing unit Niobrara “B” 4 Wells per spacing unit Niobrara “A” ACREAGE Whiting has assembled 120,354 gross (87,610 net) acres in our Redtail prospect in the northeastern portion of the DJ Basin. • Average WI of 72% • Average NRI of 57% Whiting’s acreage lies along the Colorado Mineral Belt. This geological trend brackets the most productive acreage in the Niobrara formation. COMPLETED WELL COST Horizontal: $4 MM to $5.5 MM

DRILLING HIGHLIGHTS Recently completed the Razor 26-3524H flowing 861 BOEPD from the Niobrara “B” formation. Currently have one rig drilling and plan to add a second rig mid-year and a third rig before year-end.

General trend of Colorado Mineral Belt 23

Whiting Wells Whiting Lease Area

Redtail Niobrara Prospect Weld County, Colorado (March 31, 2013)

Razor 26-3524H IP: 861 BOE/D

OBJECTIVE Vertical Wolfbone Hz. Wolfcamp

ACREAGE Whiting has assembled 93,207 gross (69,163 net) acres in our Big Tex prospect in the Delaware Basin:

• Average WI of 76% • Average NRI of 57% • Well by well WI and NRI will vary based on ownership in each spacing unit.

COMPLETED WELL COST Horizontal: $7 MM - $8 MM DRILLING HIGHLIGHTS The May 2502H well was completed on January 23, 2013. It tested at a peak 24-hour rate of 674 BOPD and achieved a 30-day average peak rate of 397 BOPD. Plan to drill 3 Upper Wolfcamp wells in 2013.

May 2501 IP: 353 BOE/D

Vertical Wolfcamp Discovery Wells

Horizontal Wolfcamp Discovery Wells

May 2502H Peak 24-Hr: 674 BOPD 30-Day Avg: 397 BOPD

24

Big Tex Prospect Pecos, Reeves, and Ward Counties, Texas (March 31, 2013)

Stewart 101 IP: 232 BOE/D

Big Tex North 301H IP: 440 BOE/D

LeGear 11-02H IP: 478 BOE/D

Headquarters

Field Office

Whiting Properties

North Ward Estes & Ancillary Fields

Postle Field

CO2 Pipeline

MID-CONTINENT McElmo

Dome

Bravo

Dome

DENVER CITY PERMIAN

25

EOR Projects Postle and North Ward Estes Fields

Whiting

Postle Total % Postle

N. Ward Estes Whiting N. Ward Estes

12/31/12 Proved Reserves(1)

Oil – MMBbl 180.1 121.2 301.3 40%

NGL - MMNgl 19.3 20.8 40.1 52%

Gas – Bcf 199.1 25.2 224.3 11%

Total – MMBOE 232.6 146.2(2)(3) 378.8 39% (2)

% Crude Oil 77% 83% 80%

Q1 2013 Production

Total – MBOE/d 72.9 16.2 89.1 18%

(1) Based on independent engineering by Cawley, Gillespie & Associates, Inc. at December 31, 2012. (2) Includes Ancillary Properties (3) Since their acquisition in late 2004 and early 2005, through December 31, 2012 Postle and North Ward Estes has produced 39.0 MMBOE net to Whiting.

60,377 Net Acres

Project Timing and Net Reserves(1)

Injection CO2 Project Start Date

2007 - 2014

2009 - 2019

2010 - 2025

2013 - 2025

2013 - 2027

2016 - 2030

2018 - 2031

2019 - 2032

Totals (MMBOE)

Phase 2

Phase 3

Phase 4

Phase 5

Phase 6

Phase 7

Phase 8

Base: Primary, WF & CO2

Phase 1

PVPD

Other

Proved P2 P3 Total

42 16 4 66 128

0 1 1 1 3

0 1 1 3 5

0 20 4 7 31

0 3 1 1 5

0 3 8 9 20

0 11 2 3 16

0 4 1 1 6

0 2 0 1 3

42 61 22 92 217

(1) Oil and gas reserve quantities are based on YE 2012 engineering update. 26

EOR Project North Ward Estes Field Development Plan

$0.00

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00

$80.00

2007 2008 2009 2010 2011 2012 Q1 2013

27% 20% 26% 18% 17% 18% 17%

7% 7% 7% 7% 8% 8% 8%

5% 5%

5% 5% 5% 6%

5% 3% 3%

5% 2% 2% 2% 3%

$31.29/58%

$45.10/65%

$25.71/57%

$41.58/68%

$50.65/68% $49.19/66% $49.98/67%

Lease Operating Expense Production Taxes G&A Exploration Expense EBITDA

(1) Includes hedging adjustments.

Wh

itin

g R

ealiz

ed P

rice

s(1)

$/B

OE

Consistently Delivering Strong EBITDA Margins (1)

$53.57

$69.06

$45.01

$61.48

Oil $88.11/Bbl NGL $42.56/BOE Gas $3.80/Mcf

$73.88 $69.85

27

$74.77/BOE

Consistently Good Margins

28

Whiting Highlights

•RESERVES: 80% OIL (1)

•13 YEAR R/P(1)

OIL WEIGHTED, LONG-LIVED RESERVE BASE

•9,661 GROSS (4,503.2 NET) POTENTIAL DRILLING LOCATIONS

•PROJECT +12% TO +16% YOY PRODUCTION GROWTH IN 2013

MULTI-YEAR INVENTORY TO DRIVE ORGANIC

PRODUCTION GROWTH

•16 ACQUISITIONS 2004-2012

•230.9 MMBOE AT $8.23 PER BOE ACQ COST

•ACQUIRED 704,525 NET ACRES IN THE WILLISTON BASIN 2005-2012; $526 PER NET ACRE AVERAGE

DISCIPLINED ACQUIRER WITH STRONG RECORD OF ACCRETIVE ACQUISITIONS

•TOTAL DEBT TO CAP OF 37.3% AS OF MAR-31-13 COMMITMENT TO

FINANCIAL STRENGTH

•AVERAGE 29 YEARS EXPERIENCE PROVEN MANAGEMENT AND TECHNICAL TEAM

(1) Percent oil reserves and R/P ratio based on year-end 2012 proved reserves and total 2012 production.

Documents

Wll june 2013