Whiting Corporate Presentation

Whiting Petroleum Corporation

Current Corporate Information March 2012

Drilling operations at Whiting‟s Redtail Prospect in the

Denver Basin in Weld County, CO. Following up on its

Wildhorse 16-13H discovery well on the Redtail

Prospect in February 2012, Whiting drilled 12 miles to

the northeast and completed the Horsetail 18-0733H

well for 718 BOE/d.

In the fourth quarter of 2011 and to date in the first quarter of 2012, Whiting drilled

10 notable wells on the Pronghorn Prospect in Stark and Billings Counties, ND.

These notable wells IP‟d at an average of 2,565 BOE/d.

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

Resource Information, Definition of De-Risked

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, 2011. 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.

In this presentation, “De-Risked” core development acreage and related well locations in the Williston Basin refers to acreage and locations that the

Company believes the relative geological risks related to recovery have been reduced as a result of drilling operations to date. However, only a small

portion of such acreage and locations has been attributed to proved undeveloped reserves and ultimate recovery from such acreage and locations remains

subject to all the recovery risks applicable to other acreage.

1

Company Overview

Drilling the Hutchins Stock Association #1096 in North

Ward Estes Field, Whiting‟s EOR project in Ward and

Winkler Counties, Texas.

(1) Assumes a $57.16 share price (closing price as of March 14, 2012) on 117,380,884 common shares outstanding as of December 31, 2011.

(2) As of December 31, 2011. Please refer to the “Outstanding Bonds and Credit Agreement” slide for details.

(3) As of December 31, 2011. Please refer to the “Total Capitalization” slide for details.

(4) Whiting reserves at December 31, 2011 based on independent engineering.

(5) R/P ratio based on year-end 2011 proved reserves and 2011 production.

Market Capitalization(1) $6.7 B

Long-Term Debt(2) $1,380 MM

Shares Outstanding 117.4 MM

Debt/Total Cap(3) 31.4%

Proved Reserves(4) 345.2 MMBOE

% Oil 86%

R/P ratio(5) 13.9 years

Q4 2011 Production 70.7 MBOE/d

2

4% 2%

12%

19%

63%

Michigan Gulf Coast

Mid-Continent Permian Basin

Rocky Mountains

ROCKY MOUNTAINS

44.4 MBOE/D

PERMIAN

13.4 MBOE/D

MID-CONTINENT

8.4 MBOE/D

MICHIGAN

2.8 MBOE/D

GULF COAST

1.7 MBOE/D

Map of Operations

Q4 2011 Net Production

70.7 MBOE/d

3

46%

2%

12%3%

37%

Rocky Mountains Permian Basin

Gulf Coast Mid-Continent

Michigan

Platform for Continued Growth (1)

345.2 MMBOE Proved Reserves (12/31/2011)

86% Oil / 14% Natural Gas

(1) Whiting reserves at December 31, 2011 based on independent engineering.

4

Whiting Pre-Tax PV10% Values at December 31, 2011 (1)

- Using SEC NYMEX of $96.19/Bbl and $4.12/Mcf Held Flat

Proved Reserves (1)

Core Area

Oil (MMBbl)(2)

Natural Gas (Bcf)

Total (MMBOE)

%

Oil(2)

Pre-Tax PV10% Value(3)

(In MM)

Rocky Mountains 132.2 162.3 159.2 83% $ 4,157.1

Permian Basin 122.5 38.1 128.8 95% $2,011.6

Other(4) 43.1 84.6 57.2 75% $1,236.0

Total 297.8 285.0 345.2 86% $ 7,404.7

(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, 2011, pursuant to current SEC and FASB

guidelines. The NYMEX prices used were $96.19/Bbl and $4.12/MMBtu.

(2) Oil includes natural gas liquids.

(3) Pre-tax PV10% 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, 2011, our

discounted future income taxes were $2,132.2 million and our standardized measure of after-tax discounted future net cash flows was $5,272.5

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.

(4) Other consists of Mid-Continent, Michigan, and Gulf Coast.

5

Probable Reserves (1)

Core Area

Oil (MMBbl)(2)

Natural Gas

(Bcf) Total

(MMBOE)

%


Oil(2) (In MM)

Rocky Mountains 24.7 133.5 46.9 53% $ 375.9 Permian Basin 36.9 53.0 45.8 81% $ 576.6 Other(4) 9.2 24.4 13.2 69% $ 83.9

Total 70.8 210.9 105.9 67% $ 1,035.4

Possible Reserves (1)

Core Area

Oil (MMBbl)(2)

Natural Gas

(Bcf) Total

(MMBOE)

%


Oil(2) (In MM)

Rocky Mountains 59.2 150.0 84.3 70% $ 1,086.9 Permian Basin 101.9 8.9 103.3 99% $ 861.0 Other(4) 3.0 28.3 7.7 39% $ 75.9

Total 164.1 187.2 195.3 84% $ 2,023.8

(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, 2011, pursuant to SEC and FASB guidelines. The

NYMEX prices used were $96.19/Bbl and $4.12/MMBtu.


(3) Pre-tax PV10% amounts above 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

(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, 2011, pursuant to SEC and FASB guidelines. The

NYMEX prices used were $96.19/Bbl and $4.12/MMBtu.


(3) Pre-tax PV10% amounts above represent the present value of estimated future revenues to be generated from the production of resource potential

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% values of resource potential reserves, there do not exist any directly comparable US GAAP measures and such amounts do

not purport to present the fair value of our resource potential reserves.


Resource Potential (1)

Core Area

Oil (MMBbl)(2)

Natural Gas

(Bcf) Total

(MMBOE)

%


Oil(2) (In MM)

Rocky Mountains 297.4 506.7 381.9 78% $ 3,945

Permian Basin 59.9 86.1 74.2 81% $ 707

Other (4) 7.4 91.8 22.6 32% $ 82

Total 364.7 684.6 478.7 76% $ 4,734



7

Future Drilling Locations(1)

8

(1) Please refer to the beginning of this presentation for disclosures regarding “Forward Looking Statements” and “Reserve and Resource Information”.

(2) Includes 203 gross (108 net) PUD locations.

Total 3P Drilling Locations

Gross Net

Northern Rockies(2) 707 334

Central Rockies 421 283

Permian Basin 838 338

Mid-Continent 210 189

Gulf Coast 72 58

Michigan 16 13

Total 2,264 1,215

Total Resource Drilling Locations

Gross Net

Northern Rockies 1,839 640

Central Rockies 1,416 889

Permian Basin 417 307

Mid-Continent 6 1

Gulf Coast 34 31

Michigan 29 22

Total 3,741 1,890

Capital Budget for Key Development

Areas in 2012 ($ in millions)

(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 primarily of exploration salaries, lease delay rentals, seismic, other exploration and development and timing adjustments.

Land

$136MM

Central Rockies

$50MM

Permian

$60MM EOR

$177MM

Exploration

Expense(2)

$56MM

Facilities

$228MM

Non-Op

$42MM Northern Rockies

$851MM2012

CAPEX (MM $) %

Gross Wells

Net Wells

Northern Rockies $ 851 53% 218 124

EOR $ 177 11% NA(1) NA(1)

Permian $ 60 4% 13 13

Central Rockies $ 50 3% 11 11

Non-Operated $ 42 3%

Land $ 136 9%

Exploration Expense (2) $ 56 3%

Facilities $ 228 14%

Total Budget $ 1,600 100% 242 148

9

All Whiting Lease Areas In Williston Basin Plays at

December 31, 2011

(1) As of 12/31/2011, Whiting’s total acreage cost in

681M net acres is approximately $294 million, or $432

per net acre.

MISSOURI

BREAKS

LEWIS

& CLARK

CASSANDRA

BIG

ISLAND

SANISH &

PARSHALL

10

8 6

4

2

1

9

7

5

A‟

A

STARBUCK

HIDDEN

BENCH

TARPON 3

Gross Acres Net Acres

Sanish / Parshall 177,399 83,062

- Middle Bakken / Three Forks Objectives

Lewis & Clark / Pronghorn 385,665 256,296

- Three Forks Objective

Hidden Bench 59,894 29,354


Tarpon 8,125 6,265


Starbuck 103,282 87,685


Missouri Breaks 58,840 40,290


Cassandra 30,661 14,501


Big Island 170,706 121,885

- Multiple Objectives

Other ND & Montana 109,957 42,166

1,104,529 681,504(1)

Pronghorn

10

Whiting Drilling Objectives in the Western Williston Basin

-- Shooting for the “Sweet Spots”

A‟ A

Please note dual targets in the Middle Bakken and

Pronghorn Sand / Upper Three Forks

11

Whiting Williston Basin

Unconventional Prospects

December 31, 2011

Whiting Interest Spacing Units

Whiting De-Risked Areas To Date

Whiting Prospect Areas

De-Risked Map – Williston Basin (1)(2)

STARBUCK 103,282 Prospect Gross Acres

87,685 Prospect Net Acres

LEWIS & CLARK 215,199 Prospect Gross Acres


98,992 De-Risk Gross Acres (46%)

64,193 De-Risk Net Acres

HIDDEN BENCH 59,894 Prospect Gross Acres


100% De-Risked

TARPON 8,125 Prospect Gross Acres


100% De-Risked

CASSANDRA 30,661 Prospect Gross Acres


100% De-Risked

PRONGHORN 170,466 Prospect Gross Acres


101,453 De-Risk Gross Acres (60%)

68,649 De-Risk Net Acres

Bakken Pinch-Out

BIG ISLAND 170,706 Prospect Gross Acres


640 De-Risk Gross Acres (<1%)

621 De-Risk Net Acres

SANISH 108,815 Prospect Gross Acres


100% De-Risked

PARSHALL 68,584 Prospect Gross Acres


100% De-Risked

MISSOURI BREAKS 58,840 Prospect Gross Acres


12

(1) Whiting unconventional acreage

totals 681,504 net acres.

(2) Please refer to the beginning of

this presentation for a definition of

"De-Risked“.

13

Typical Bakken Production Profiles Sanish Field (1) (2)

Production Profiles in Oil Equivalents

Bakken - Sanish

10

100

1,000

10,000

0 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180

Months On Production

Eq

uiv

ale

nt

Daily P

rod

ucti

on

BO

E/D

EUR - 950 MBOE

EUR - 450 MBOE

EUR - 950 MBOE, CAPEX $6MM

Nymex oil price/Bbl $80 $90 $100

ROI 6.7:1 7.7:1 8.8:1

IRR (%) 498% 809% 1,303%

Payout (Yrs.) 0.6 0.5 0.5

PV(10) $MM 19.43 23.31 27.19

EUR - 450 MBOE , CAPEX $6MM


ROI 2.7:1 3.2:1 3.7:1

IRR (%) 70% 104% 148%

Payout (Yrs.) 1.4 1.0 0.9

PV(10) $MM 5.46 7.36 9.27

(1) Please refer to the beginning of this presentation for disclosures regarding "Reserve and Resource Information." All volumes shown are un-risked. Our

pretax 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. Whiting holds an average WI of 60% and an average NRI of 50% in its operated Bakken wells in

Sanish field.

14

Typical Three Forks Production Profile Sanish Field (1) (2)

Production Profile in Oil Equivalents

Three Forks - Sanish

10

100

1,000

0 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180

Months On Production

Eq

uiv

ale

nt

Da

ily

Pro

du

cti

on

BO

E/D

EUR - 400 MBOE

EUR - 400 MBOE , CAPEX $6 MM


ROI 2.5:1 2.9:1 3.4:1

IRR (%) 50% 73% 105%

Payout (Yrs.) 1.8 1.4 1.1

PV(10) $MM 4.35 6.07 7.79

(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. Whiting holds an average WI of 60% and an average NRI of 50% in its operated Three Forks

wells in Sanish field.

Typical Non-Sanish Field Bakken or Pronghorn

Sand / Three Forks Well Expected Results(1)

10

100

1000

0 20 40 60 80 100 120 140 160 180

Daily E

qu

av

len

t O

il R

ate

Months on Production

EUR – 600 MBOE

(Avg 1st 30 days 830 BOE/d)

EUR – 350 MBOE

(Avg 1st 30 days 430 BOE/d)

(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.

Oil Price ($/Bbl) 90.00 100.00

ROI 3.7 4.2

Payout (yrs) 0.9 0.8

PV10 ($MM) 11.03 13.28

IRR 155% 213%

Oil Price ($/Bbl) 90.00 100.00

ROI 2.0 2.3

Payout (yrs) 2.3 1.9

PV10 ($MM) 3.23 4.57

IRR 35% 47%

EUR 350 MBOE, Capex $7.0 MM

EUR 600 MBOE, Capex $7.0 MM

15

Average IP and 30, 60, 90 Day Production(1)(2) of

Whiting Operated Wells

(1) Based on actual days on production.

(2) January 1, 2011 - December 31, 2011

(3) Inception - December 31, 2011. 16

Sanish Bakken(2)

Avg WI % Avg NRI % Avg IP BOE/d

24-hr Test Avg 1st 30 Day Avg 1st 60 Day Avg 1st 90 Day

No. of Wells 31 31 31 28 24 16 Averages 67% 54% 2,018 760 648 528

Sanish Three Forks(2)


24-hr Test Avg 1st 30 Day Avg 1st 60 Day Avg 1st 90 Day No. of Wells 44 44 44 16 7 4 Averages 62% 50% 787 383 281 288

Lewis & Clark / Pronghorn(3)


24-hr Test Avg 1st 30 Day Avg 1st 60 Day Avg 1st 90 Day

No. of Wells 44 44 44 41 37 33

Averages 79% 63% 1,312 565 435 376

Hidden Bench / Tarpon(3)


24-hr Test Avg 1st 30 Day Avg 1st 60 Day Avg 1st 90 Day No. of Wells 8 8 8 5 3 3

Averages 68% 55% 2,904 941 1,040 930

Six Month Cumulative Production by Operator For Bakken Wells Drilled Since January 2009

& Operators With Greater Than 10 Wells Producing Source: IHS Energy, Inc. & North Dakota Industrial Commission (As of February 2012)

17

TransCanada

Keystone XL

Existing Pipelines

Proposed Pipelines

Williston Basin Off-Take Expansion (1)

(1) Projected additions based on publicly available information. 18

All Volumes Barrels per Day Existing Capacity 2012 2013

Total Additions Additions

Enbridge 210,000 145,000 Q4 355,000

Bridger / Belle Fourche 150,000 50,000 Q1 100,000 Q1 300,000

Tesoro /Mandan 60,000 60,000

EOG (rail) 60,000 60,000

Plains 50,000 Q4 50,000

Hess (rail) 60,000 Q1 60,000

COLT (rail) 27,000 Q2 27,000

Lario (rail) 100,000 100,000 Q3 200,000

Savage (rail) 90,000 Q2 90,000

Quintana (rail) 90,000 Q1 90,000

Total 580,000 522,000 190,000 1,292,000

Big Tex Prospect Pecos, Reeves and Ward Counties, Texas

OBJECTIVE

Bone Spring

Wolfcamp

ACREAGE

Whiting has assembled 120,719

gross (89,820 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

Vertical: $3 MM - $4.5 MM

Horizontal: $5 MM

DRILLING PROGRAM

2 rigs currently active in the

area. Plan to drill 13 wells in

2012. Planned budget for the

prospect in 2012 is $57 MM.

Developing Bone Spring

prospect. Evaluating horizontal

Wolfcamp and vertical Wolfbone

potential.

19

Redtail Niobrara Prospect Weld County, Colorado

OBJECTIVE

Niobrara Shale

ACREAGE

Whiting has assembled 105,597

gross (73,611 net) acres in our

Redtail prospect in the

northeastern portion of the DJ

Basin

• Average WI of 70%

• Average NRI of 57%

• Well by well WI and NRI will

vary based on ownership in

each spacing unit

COMPLETED WELL COST

Horizontal: $4 to $5.5 MM

DRILLING PROGRAM

Recently completed its first well

drilled on a 960-acre spacing

unit, the Horsetail 18-0733H.

Plan to drill 8 wells in 2012.

Redtail 73,611 Net Acres

.

Wild Horse 16-13H

General trend of Colorado Mineral Belt

.

20

Horsetail 18-0733H

.

Whiting Postle

N. Ward Estes Total

Whiting

% Postle N. Ward

Estes

12/31/11 Proved Reserves(1)

Oil – MMBbl 167 131 298 44%

Gas – Bcf 263 22 285 8% Total – MMBOE 210 135

(2) 345 39%

(2)

% Crude Oil 79% 97% 86%

Q4 2011 Production

Total – MBOE/d 53.9 16.8 70.7 24% (1)

Based on independent engineering by Cawley, Gillespie & Associates, Inc. at December 31, 2011. (2)

Includes Ancillary Properties

EOR Projects - Postle and North Ward Estes Fields

Headquarters

Field Office

Whiting Properties

North Ward Estes & Ancillary Fields

Postle Field

CO2 Pipeline

MID-CONTINENT McElmo

Dome

Bravo

Dome

DENVER CITY PERMIAN

21

8,795 BOE/d

0

5

10

15

20

25

North Ward Estes 3P Unrisked Production Forecast (2)

Proved

P1 + P2

P1 + P2 + P3

2012

Jun

„05 Q4.

„11 2020

285 – 300 MMcf/d

Current CO2 Injection

(1) Based on independent engineering by Cawley, Gillespie & Associates, Inc. at December 31, 2011. Includes ancillary fields. Please refer to the beginning of this presentation for disclosures

regarding "Reserve and Resource Information." All volumes shown are unrisked.

(2) Production forecasts based on assumptions in December 31, 2011 reserve report. After 2020, North Ward Estes field proved reserve production is expected to decline at 5% - 7% year over year.

North Ward Estes - Net Production Forecasts (1)

Magnitude and timing of results could vary.

Pro

du

cti

on

Rate

Mb

oe

/d

22

(1) Based on independent engineering at Dec. 31, 2011. Please refer to the beginning of the presentation for

disclosures regarding “Reserve and Resource Information.” All volumes shown are unrisked. 23

Development Plans – North Ward Estes Field Ward and Winkler Counties, Texas

58,000 Net Acres

Project Timing and Net Reserves (1)

Injection

CO2 Project Start Date

2007 - 2008

2009 - 2010

2010 - 2015

2011

2012 - 15

2015

2016

2016

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

44 4 6 60 114

0 2 2 2 6

0 0 2 4 6

0 25 4 8 37

0 4 1 1 6

0 3 9 9 21

0 10 2 3 15

0 5 1 1 7

0 3 0 1 4

44 56 27 89 216

58,000 Net Acres

Phase 1 2007 - 2008

2009 - 2010

2010 - 2015

2011

2012 - 2015

2015

2016

2016

Phase 2

Phase 3

Phase 4

Phase 5

Phase 6

Phase 7

Phase 8

Injection

CO2 Project Start Date

Development Plans – North Ward Estes Field Ward and Winkler Counties, Texas

Total 2012 - 2040 Remaining

Capital Expenditures (1)

(In Millions)

CapEx (2)

Drilling, Completion, Workovers

& Gas Plant Costs $ 515

CO2 Purchases 1,439

Total $1,954

(1) Based on independent engineering at Dec. 31, 2011.

(2) Consists of CapEx for Proved, Probable and Possible reserves. Please refer to the beginning

of this presentation for disclosures regarding "Reserve and Resource Information."

24

Consistently Strong Margins

(1) Includes hedging adjustments.

$0.00

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00

$80.00

2005 2006 2007 2008 2009 2010 2011

20% 24% 27% 20% 26% 18% 17% 7%

6% 7% 7%

7% 7% 8% 6% 5%

5% 5% 5% 5%

5% 3%

4% 3%

3%

5% 2% 2%

$28.73/64%

$30.82/61% $31.29/58%

$45.10/65%

$25.71/57%

$41.58/68%

$50.65/68%

Lease Operating Expense Production Taxes G&A Exploration Expense EBITDA

Wh

itin

g R

ea

lize

d P

ric

es

(1)

$/B

OE

Consistently Delivering Strong EBITDA Margins (1)

$44.70

$50.52 $53.57

$69.06

$45.01

$61.48

$84.09/Bbl

$4.77/Mcf

$73.88/BOE

25

Steady Production Growth

2005 2006 2007 2008 2009 2010 2011 2012E

33.1 41.5 40.3

47.9 55.5

64.6 67.9

79.2

Production A

ve

rag

e D

ail

y P

rod

ucti

on

(M

BO

E/d

) 12% CAGR Production 2005 – 2012E(1)

26

(1) Represents the mid-point of 2012 full year production guidance range

Total Capitalization ($ in thousands)

Dec. 31, Dec. 31,

2011 2010

Cash and Cash Equivalents $ 15,811 $ 18,952

Long-Term Debt:

Credit Agreement $ 780,000 $ 200,000

Senior Subordinated Notes 600,000 600,000

Total Long-Term Debt $1,380,000 $ 800,000

Stockholders‟ Equity 3,020,857 2,531,315

Total Capitalization $4,400,857 $3,331,315

Total Debt / Total Capitalization 31.4% 24.0%

27

Outstanding Bonds and Credit Agreement

7.00% / Sr. Sub. – NC

Coupon / Description Amount

02/01/2014

Outstanding Maturity Ratings

Moody‟s / S&P

$250.0 mil. Ba3 / BB+

6.50% / Sr. Sub. – NC4 10/01/2018 $350.0 mil. Ba3 / BB+

● Bond Finance Covenant: Ratio of pre-tax earnings to fixed charges (interest expense) must be greater than

2:1. It was 14.78:1 at 12/31/11.

● Restricted Payments Basket: Approximately $2.1 billion.

● Bank Credit Agreement size is $1.5 billion under which $780 million was drawn as of 12/31/11. Weighted average

Interest rate is currently 2.36%. Redetermination date is 5/1/12.

● Bank Credit Agreement Covenants: Total debt to EBITDAX at 12/31/11was 1.05:1 (must be less than 4.25:1)

Working capital at 12/31/11 was 1.95:1 (must be greater than 1:1)

Price

106.75

106.75

2/1/12

28

Oil weighted, long-lived reserve base Reserves 86% oil; 13.9 year R/P (1)

Multi-year inventory to drive organic production growth

2,264 3P and 3,741 Resource future drilling locations; Project 14 - 20% YoY production growth in 2012

Disciplined acquirer with strong record of accretive acquisitions

16 acquisitions in 2004 – 2011; 230.9 MMBOE at $8.23 per BOE average acquisition cost; Acquired 681,504 acres in the Williston Basin 2005 – 2012; $432 per acre average

Commitment to financial strength Total Debt to Cap of 31.4% as of December 31, 2011

Proven management and technical team Average 28 years of experience

In Summary

(1) Percent oil reserves and R/P ratio based on year-end 2011 proved reserves and total 2011 production. 29

Existing Crude Oil Hedge Positions(1)

Disciplined Hedging Strategy

Utilize hedges to manage exposure against potential commodity price declines while maintaining pricing upside

Employ mix of contracts weighted toward the short-term

Existing Natural Gas Hedge Positions(1)

(1) As of January 31, 2012.

Hedge Period

Contracted Volume (Bbls per

Month)

Weighted Average NYMEX Price Collar

Range (per Bbl)

As a Percentage of December 2011 Oil Production

Hedge Period

Contracted Volume (MMBtu

per Month)

Weighted Average NYMEX Price Collar Range (per MMBtu)

As a Percentage of December 2011 Gas Production

2012 2012

Q1 984,054 $66.63 - $108.56 51.20% Q1 33,381 $7.00 - $15.55 1.60%

Q2 983,850 $66.63 - $108.56 51.20% Q2 32,477 $6.00 - $13.60 1.60%

Q3 983,650 $66.63 - $108.55 51.10% Q3 31,502 $6.00 - $14.45 1.50%

Q4 983,477 $66.63 - $108.55 51.10% Q4 30,640 $7.00 - $13.40 1.50%

2013

Q1 290,000 $47.67 - $90.21 15.10%

Q2 290,000 $47.67 - $90.21 15.10%

Q3 290,000 $47.67 - $90.21 15.10%

Oct 290,000 $47.67 - $90.21 15.10%

Nov 190,000 $47.22 - $85.06 9.90%

30

Fixed-Price Marketing Contracts

Existing Natural Gas Marketing Contracts(1)

Weighted Average As a Percentage of

Hedge Contracted Volume Contracted Price December 2011

Period (MMBtu per Month) (per MMBtu) Gas Production

2012

Q1 576,963 $5.30 27.7%

Q2 461,296 $5.41 22.1%

Q3 465,630 $5.41 22.4%

Q4 398,667 $5.46 19.1%

2013

Q1 360,000 $5.47 17.3%

Q2 364,000 $5.47 17.5%

Q3 368,000 $5.47 17.7%

Q4 368,000 $5.47 17.7%

2014

Q1 330,000 $5.49 15.8%

Q2 333,667 $5.49 16.0%

Q3 337,333 $5.49 16.2%

Q4 337,333 $5.49 16.2%

31

(1) As of January 31, 2012.

Adjusted Net Income (1)

(In Thousands)

Reconciliation of Net Income Available to Common Shareholders to

Adjusted Net Income Available to Common Shareholders

(1) Adjusted Net Income Available to Common Shareholders is a non-GAAP financial measure. Management believes it provides useful information to investors for analysis of Whiting’s fundamental business on a recurring basis. In addition, management believes that Adjusted Net Income Available to Common Shareholders is widely used by professional research analysts and others in valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted Net Income Available for Common Shareholders should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities or other income, cash flow or liquidity measures under US GAAP and may not be comparable to other similarly titled measures of other companies.

(2) All per share amounts have been retroactively restated for the 2010 periods to reflect the Company’s two-for-one stock split in February 2011.

32

Three Months Ended Twelve Months Ended

December 31, December 31, 2011 2010 2011 2010

Net Income Available to Common Shareholders $ 62,620 $ 65,925 $ 490,610 $ 272,683

Cash Premium on Induced Conversion - - - 47,529

Adjustments Net of Tax: Amortization of Deferred Gain on Sale (2,227) (2,521) (8,781) (9,708) (Gain) Loss on Sale of Properties (1,012) 334 (10,278) (863) Impairment Expense 8,869 9,119 24,435 16,492

Loss on Early Extinguishment of Debt - - - 3,877

Unrealized Derivative (Gains) Losses 56,273 26,137 (39,751) (25,329) Adjusted Net Income (1) $ 124,523 $ 98,994 $ 456,235 $ 304,681

Adjusted Net Income Available to Common Shareholders per Share, Basic (2) $ 1.06 $ 0.85 $ 3.89 $ 2.99

Adjusted Net Income Available to Common Shareholders per Share, Diluted (2) $ 1.05 $ 0.84 $ 3.85 $ 2.71

Discretionary Cash Flow (1)

Reconciliation of Net Cash Provided by Operating Activities to

Discretionary Cash Flow (In Thousands)

(1) Discretionary cash flow is computed as net income plus exploration and impairment costs, depreciation, depletion and amortization, deferred income taxes, non-

cash interest costs, losses on early extinguishment of debt, non-cash compensation plan charges, non-cash losses on mark-to-market derivatives and other non-

current items, less the gain on sale of properties, amortization of deferred gain on sale, non-cash gains on mark-to-market derivatives, and preferred stock

dividends paid, not including preferred stock conversion inducements. The non-GAAP measure of discretionary cash flow is presented because management

believes it provides useful information to investors for analysis of the Company’s ability to internally fund acquisitions, exploration and development.

Discretionary cash flow should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities

or other income, cash flow or liquidity measures under US GAAP and may not be comparable to other similarly titled measures of other companies.

Three Months Ended Twelve Months Ended

December 31, December 31,

2011 2010 2011 2010

Net cash provided by operating activities $328,329 $277,022 $1,192,083 $997,289

Exploration 9,455 6,985 45,861 32,846

Exploratory dry hole costs (210) (1,023) (4,924) (3,819)

Changes in working capital (8,496) (5,555) 10,762 (60,545)

Preferred stock dividends paid (269) (269) (1,077) (16,441)

Discretionary cash flow (1) $328,809 $277,160 $1,242,705 $949,330

33

Guidance for Q1 and Full-Year 2012(1)

34

(1) Includes the effect of Whiting’s fixed-price gas contracts. Please refer to fixed-price gas contracts later in this

presentation.

Guidance First Quarter Full-Year 2012 2012

Production (MMBOE) ................................................ 6.80 - 7.20 28.30 - 29.70

Lease operating expense per BOE ............................. $ 12.80 - $ 13.10 $ 13.00 - $ 13.40

General and admin. expense per BOE ....................... $ 3.60 - $ 3.80 $ 3.70 - $ 3.90

Interest expense per BOE ........................................ $ 2.55 - $ 2.75 $ 2.50 - $ 2.70

Depr., depletion and amort. per BOE ........................ $ 20.00 - $ 20.50 $ 20.50 - $ 20.90

Prod. taxes (% of production revenue) ..................... 7.8% - 8.0% 7.9% - 8.2%

Oil price differentials to NYMEX per Bbl ..................... ($13.00) - ($14.00) ($10.50) - ($11.50)

Gas price premium to NYMEX per Mcf (1) ................... $ 0.60 - $ 0.90 $ 0.60 - $ 0.90

Whiting Corporate Presentation

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