April Corporate Presentation by Whiting

Whiting Petroleum Corporation 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 IPâ&#x20AC;&#x;d at an average of 2,565 BOE/d.

Current Corporate Information April 2012

Drilling operations at Whitingâ&#x20AC;&#x;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.

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.

Company Overview

Drilling the Hutchins Stock Association #1096 in North Ward Estes Field, Whiting‟s EOR project in Ward and Winkler Counties, Texas.

(1) (2) (3) (4) (5)

Market Capitalization(1)

$6.5 B

Long-Term Debt(2)

$1,380 MM

Shares Outstanding

117.4 MM

Debt/Total Cap(3)

31.4%

Proved Reserves(4) % Oil

345.2 MMBOE 86%

R/P ratio(5)

13.9 years

Q4 2011 Production

70.7 MBOE/d

Assumes a $55.12 share price (closing price as of April 2, 2012) on 117,380,884 common shares outstanding as of December 31, 2011. As of December 31, 2011. Please refer to the “Outstanding Bonds and Credit Agreement” slide for details. As of December 31, 2011. Please refer to the “Total Capitalization” slide for details. Whiting reserves at December 31, 2011 based on independent engineering. R/P ratio based on year-end 2011 proved reserves and 2011 production.

Map of Operations ROCKY MOUNTAINS 44.4 MBOE/D MICHIGAN 2.8 MBOE/D

Q4 2011 Net Production 70.7 MBOE/d 4% 2% 12%

MID-CONTINENT 8.4 MBOE/D

19% 63%

PERMIAN 13.4 MBOE/D

Michigan

Gulf Coast

Mid-Continent

Permian Basin

Rocky Mountains

GULF COAST 1.7 MBOE/D 3

Platform for Continued Growth (1) 345.2 MMBOE Proved Reserves (12/31/2011) 3% 12% 2% 46%

37%

Rocky Mountains Gulf Coast Michigan ď ľ

86% Oil / 14% Natural Gas

Permian Basin Mid-Continent

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

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

Core Area Rocky Mountains Permian Basin Other(4) Total

(1)

Oil (MMBbl)(2)

Natural Gas (Bcf)

Total (MMBOE)

% Oil(2)

Pre-Tax PV10% Value(3) (In MM)

132.2 122.5 43.1 297.8

162.3 38.1 84.6 285.0

159.2 128.8 57.2 345.2

83% 95% 75% 86%

$ 4,157.1 $2,011.6 $1,236.0 $ 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.

Whiting Pre-Tax PV10% Values at December 31, 2011 (1) - Using SEC NYMEX of $96.19/Bbl and $4.12/Mcf Held Flat

Core Area Rocky Mountains Permian Basin Other(4) Total

Oil (MMBbl)(2) 24.7 36.9 9.2 70.8

Probable Reserves (1) Natural % Gas Total (Bcf) (MMBOE) Oil(2) 133.5 53.0 24.4 210.9

46.9 45.8 13.2 105.9

53% 81% 69% 67%

Pre-Tax PV10% Value(3) (In MM) $ $ $ $

375.9 576.6 83.9 1,035.4

Possible Reserves (1)

Core Area Rocky Mountains Permian Basin Other(4) Total

Oil (MMBbl)(2) 59.2 101.9 3.0 164.1

Natural Gas (Bcf) 150.0 8.9 28.3 187.2

Total (MMBOE) 84.3 103.3 7.7 195.3

% Oil(2) 70% 99% 39% 84%

Pre-Tax PV10% Value(3) (In MM) $ $ $ $

1,086.9 861.0 75.9 2,023.8

Whiting Pre-Tax PV10% Values at December 31, 2011 (1) - Using SEC NYMEX of $96.19/Bbl and $4.12/Mcf Held Flat

Core Area Rocky Mountains Permian Basin Other (4) Total

Oil (MMBbl)(2) 297.4 59.9 7.4 364.7

Resource Potential (1) Natural % Gas Total (Bcf) (MMBOE) Oil(2) 506.7 86.1 91.8 684.6

381.9 74.2 22.6 478.7

78% 81% 32% 76%

Pre-Tax PV10% Value(3) (In MM) $ $ $ $

3,945 707 82 4,734

Future Drilling Locations(1) Total 3P Drilling Locations Gross Net Northern Rockies(2) Central Rockies Permian Basin Mid-Continent Gulf Coast Michigan Total

707 334 421 283 838 338 210 189 72 58 16 13 2,264 1,215

Total Resource Drilling Locations Northern Rockies Central Rockies Permian Basin Mid-Continent Gulf Coast Michigan Total

Gross Net 1,839 640 1,416 889 417 307 6 1 34 31 29 22 3,741 1,890

(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. 8

Capital Budget for Key Development Areas in 2012 ($ in millions)

Facilities $228MM Exploration Expense (2) $56MM Land $136MM

(1) (2)

Northern Rockies $851MM

Northern Rockies

2012 CAPEX (MM $) $ 851

Gross % Wells 53% 218

EOR

177

11%

NA(1)

Permian

Central Rockies

Non-Operated

136

Facilities

228

14%

Total Budget

$ 1,600 100%

242

148

Land

Central Rockies $50MM Permian $60MM

Non-Op $42MM

Exploration Expense

(2)

Net Wells 124

EOR $177MM

These multi-year CO2 projects involve many re-entries, workovers and conversions. Therefore, they are budgeted on a project basis not a well basis. Comprised primarily of exploration salaries, lease delay rentals, seismic, other exploration and development and timing adjustments.

All Whiting Lease Areas In Williston Basin Plays at December 31, 2011 Gross Acres Net Acres Sanish / Parshall

177,399

83,062

385,665

256,296

59,894

29,354

8,125

6,265

103,282

87,685

58,840

40,290

30,661

14,501

170,706

121,885

109,957

42,166

- Middle Bakken / Three Forks Objectives Lewis & Clark / Pronghorn - Three Forks Objective

CASSANDRA

1 STARBUCK

SANISH & PARSHALL

Hidden Bench - Middle Bakken / Three Forks Objectives Tarpon - Middle Bakken / Three Forks Objectives Starbuck

3 TARPON

MISSOURI BREAKS

- Middle Bakken / Three Forks Objectives Missouri Breaks

HIDDEN BENCH

- Middle Bakken / Three Forks Objectives

Cassandra - Middle Bakken / Three Forks Objectives Big Island - Multiple Objectives Other ND & Montana

LEWIS 5 & CLARK

67 BIG ISLAND

1,104,529

681,504(1)

8 9

Pronghorn

A‟ (1)

As of 12/31/2011, Whiting’s total acreage cost in 681M net acres is approximately $294 million, or $432 per net acre.

Whiting Drilling Objectives in the Western Williston Basin -- Shooting for the “Sweet Spots”

A‟

Please note dual targets in the Middle Bakken and Pronghorn Sand / Upper Three Forks

De-Risked Map – Williston Basin (1)(2) STARBUCK 103,282 Prospect Gross Acres 87,685 Prospect Net Acres

CASSANDRA

SANISH

30,661 Prospect Gross Acres 14,501 Prospect Net Acres 100% De-Risked

108,815 Prospect Gross Acres 66,480 Prospect Net Acres 100% De-Risked

TARPON 8,125 Prospect Gross Acres 6,265 Prospect Net Acres 100% De-Risked

PARSHALL 68,584 Prospect Gross Acres 16,582 Prospect Net Acres 100% De-Risked

MISSOURI BREAKS 58,840 Prospect Gross Acres 40,290 Prospect Net Acres

HIDDEN BENCH 59,894 Prospect Gross Acres 29,354 Prospect Net Acres 100% De-Risked

Bakken Pinch-Out LEWIS & CLARK 215,199 Prospect Gross Acres 138,714 Prospect Net Acres 98,992 De-Risk Gross Acres (46%) 64,193 De-Risk Net Acres

BIG ISLAND 170,706 Prospect Gross Acres 121,885 Prospect Net Acres 640 De-Risk Gross Acres (<1%) 621 De-Risk Net Acres

PRONGHORN 170,466 Prospect Gross Acres 117,582 Prospect Net Acres 101,453 De-Risk Gross Acres (60%) 68,649 De-Risk Net Acres

Whiting Williston Basin Unconventional Prospects December 31, 2011 Whiting Prospect Areas Whiting De-Risked Areas To Date Whiting Interest Spacing Units (1) Whiting unconventional acreage totals 681,504 net acres. (2) Please refer to the beginning of this presentation for a definition of "De-Risked“.

Typical Bakken Production Profiles Sanish Field (1) (2) Production Profiles in Oil Equivalents Bakken - Sanish 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%

Equivalent Daily Production BOE/D

10,000

Payout (Yrs.)

0.6

0.5

PV(10) $MM

19.43

23.31

27.19

$80

$90

$100

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

EUR - 450 MBOE , CAPEX $6MM

1,000

Nymex oil price/Bbl

EUR - 950 MBOE

100 EUR - 450 MBOE

10 0

108 120

132

144

156

168

180

Months On Production (1) (2)

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. 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.

Typical Three Forks Production Profile Sanish Field (1) (2) Production Profile in Oil Equivalents Three Forks - Sanish

Equivalent Daily Production BOE/D

1,000

EUR - 400 MBOE , CAPEX $6 MM Nymex oil price/Bbl

$80

$90

$100

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

100 EUR - 400 MBOE

10 0

108

120

132

144

156

168

180

Months On Production (1) (2)

Typical Non-Sanish Field Bakken or Pronghorn Sand / Three Forks Well Expected Results(1) EUR 600 MBOE, Capex $7.0 MM

1000

Oil Price ($/Bbl)

90.00 3.7 0.9 11.03 155%

100.00 4.2 0.8 13.28 213%

EUR 350 MBOE, Capex $7.0 MM Oil Price ($/Bbl) 90.00 ROI 2.0 Payout (yrs) 2.3 PV10 ($MM) 3.23 IRR 35%

100.00 2.3 1.9 4.57 47%

Daily Equavlent Oil Rate

ROI Payout (yrs) PV10 ($MM) IRR

EUR – 600 MBOE (Avg 1st 30 days 830 BOE/d)

100

EUR – 350 MBOE (Avg 1st 30 days 430 BOE/d)

10 0

(1)

80 100 Months on Production

120

140

160

180

Average IP and 30, 60, 90 Day Production(1)(2) of Whiting Operated Wells Sanish Bakken(2) Avg IP BOE/d Avg WI % Avg NRI % 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) Avg IP BOE/d Avg WI % Avg NRI % 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) Avg IP BOE/d Avg WI % Avg NRI % 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) Avg IP BOE/d Avg WI % Avg NRI % 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 (1) Based on actual days on production. (2) January 1, 2011 - December 31, 2011 (3) Inception - December 31, 2011.

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)

Williston Basin Off-Take Expansion (1) Existing Pipelines Proposed Pipelines

All Volumes Barrels per Day

Existing Capacity

2013 Additions

Enbridge

210,000

145,000 Q4

Bridger / Belle Fourche

150,000

50,000 Q1

Tesoro /Mandan

60,000

EOG (rail)

60,000

355,000 100,000 Q1

300,000 60,000 60,000

50,000 Q4

50,000

Hess (rail)

60,000 Q1

60,000

Lario (rail)

100,000

Savage (rail)

27,000 Q2

27,000

100,000 Q3

200,000

90,000 Q2

Quintana (rail) Total

Total

Plains

COLT (rail)

TransCanada Keystone XL

2012 Additions

580,000

522,000

(1) Projected additions based on publicly available information.

90,000 90,000 Q1 90,000 190,000 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 Redtail 73,611 Net Acres

. Horsetail 18-0733H

Wild Horse 16-13H

• 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.

General trend of Colorado Mineral Belt 20

EOR Projects - Postle and North Ward Estes Fields

Whiting 12/31/11 Proved Reserves

Postle N. Ward Estes

Total Whiting

% Postle N. Ward Estes

(1)

Oil – MMBbl Gas – Bcf Total – MMBOE

167 263 210

131 22 (2) 135

298 285 345

79%

97%

86%

53.9

16.8

70.7

% Crude Oil

44% 8% (2) 39%

Q4 2011 Production Total – MBOE/d (1) (2)

24%

Based on independent engineering by Cawley, Gillespie & Associates, Inc. at December 31, 2011. Includes Ancillary Properties

MID-CONTINENT McElmo Dome

Headquarters

Bravo Dome

Field Office

Whiting Properties

PERMIAN

DENVER CITY

North Ward Estes & Ancillary Fields Postle Field CO2 Pipeline

North Ward Estes - Net Production Forecasts (1) North Ward Estes 3P Unrisked Production Forecast (2) 25

285 – 300 MMcf/d Current CO2 Injection

Production Rate Mboe/d

P1 + P2 + P3 15

P1 + P2

8,795 BOE/d

Proved

Jun „05

Q4. „11

2012

2020

Magnitude and timing of results could vary. (1) (2)

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. 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.

Development Plans – North Ward Estes Field Ward and Winkler Counties, Texas Project Timing and Net Reserves CO2 Project

Injection Start Date

Base: Primary, WF & CO2

PVPD

Other Proved

Total

114

Phase 1

2007 - 2008

Phase 2

2009 - 2010

Phase 3

2010 - 2015

Phase 4

2011

Phase 5

2012 - 15

Phase 6

2015

Phase 7

2016

Phase 8

2016

Totals

216

(MMBOE)

58,000 Net Acres

(1)

(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.

Development Plans â&#x20AC;&#x201C; North Ward Estes Field Ward and Winkler Counties, Texas CO2 Project

Injection Start Date

Phase 1

2007 - 2008

Phase 2

2009 - 2010

Phase 3

2010 - 2015

Phase 4

2011

Total 2012 - 2040 Remaining Capital Expenditures (1) (In Millions)

CapEx (2)

Drilling, Completion, Workovers & Gas Plant Costs CO2 Purchases

58,000 Net Acres

Phase 5

2012 - 2015

Phase 6

2015

Phase 7

2016

Phase 8

2016

Total

515 1,439

$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."

Consistently Strong Margins Consistently Delivering Strong EBITDA Margins (1) $84.09/Bbl $4.77/Mcf

Whiting Realized Prices(1) $/BOE

$73.88/BOE

$69.06

$80.00

$61.48

$70.00

$53.57

$50.52

$60.00

$45.01

$44.70 $50.00

$50.65/68%

$45.10/65% $41.58/68%

$40.00 $30.00 $20.00 $10.00

$30.82/61%

$31.29/58% $25.71/57%

$28.73/64% 3% 6% 7%

20%

4% 5% 6%

24%

3% 5% 7%

27%

20%

2% 5%

5% 5% 7%

2% 5% 7%

26%

18%

17%

$0.00

2005

2006

Lease Operating Expense

2007

2008

Production Taxes

2009 G&A

2010

2011

Exploration Expense

EBITDA

(1) Includes hedging adjustments. 25

Steady Production Growth

Average Daily Production (MBOE/d)

12% CAGR Production 2005 â&#x20AC;&#x201C; 2012E(1) Production

79.2

33.1

2005

(1)

41.5

40.3

2006

2007

47.9

2008

64.6

67.9

2010

2011

55.5

2009

2012E

Represents the mid-point of 2012 full year production guidance range 26

Total Capitalization ($ in thousands) Dec. 31, 2011

Cash and Cash Equivalents

15,811

Dec. 31, 2010

18,952

Long-Term Debt: Credit Agreement Senior Subordinated Notes Total Long-Term Debt

$ 780,000 600,000 $1,380,000

$ 200,000 600,000 $ 800,000

Stockholdersâ&#x20AC;&#x; Equity Total Capitalization Total Debt / Total Capitalization

3,020,857 $4,400,857 31.4%

2,531,315 $3,331,315 24.0%

Outstanding Bonds and Credit Agreement Ratings Amount Outstanding Moody‟s / S&P

2/1/12 Price

Coupon / Description

Maturity

7.00% / Sr. Sub. – NC

02/01/2014

$250.0 mil.

Ba3 / BB+

106.75

6.50% / Sr. Sub. – NC4

10/01/2018

$350.0 mil.

Ba3 / BB+

106.75

●

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)

In Summary

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 â&#x20AC;&#x201C; 2011; 230.9 MMBOE at $8.23 per BOE average acquisition cost; Acquired 681,504 acres in the Williston Basin 2005 â&#x20AC;&#x201C; 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

(1)

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

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 Crude Oil Hedge Positions(1) Hedge Period

Contracted Volume (Bbls per Month)

Weighted Average NYMEX Price Collar Range (per Bbl)

Existing Natural Gas Hedge Positions(1)

As a Percentage of December 2011 Oil Production

2012 Q1 Q2 Q3 Q4

984,054 983,850 983,650 983,477

$66.63 $66.63 $66.63 $66.63 -

$108.56 $108.56 $108.55 $108.55

51.20% 51.20% 51.10% 51.10%

2013 Q1 Q2 Q3 Oct Nov

290,000 290,000 290,000 290,000 190,000

$47.67 $47.67 $47.67 $47.67 $47.22 -

$90.21 $90.21 $90.21 $90.21 $85.06

15.10% 15.10% 15.10% 15.10% 9.90%

(1)

Hedge Period

2012 Q1 Q2 Q3 Q4

Contracted Volume (MMBtu per Month)

33,381 32,477 31,502 30,640

Weighted Average NYMEX Price Collar Range (per MMBtu)

$7.00 $6.00 $6.00 $7.00 -

$15.55 $13.60 $14.45 $13.40

As a Percentage of December 2011 Gas Production

1.60% 1.60% 1.50% 1.50%

As of January 31, 2012.

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

576,963

$5.30

27.7%

461,296

$5.41

22.1%

465,630

$5.41

22.4%

398,667

$5.46

19.1%

360,000

$5.47

17.3%

364,000

$5.47

17.5%

368,000

$5.47

17.7%

368,000

$5.47

17.7%

330,000

$5.49

15.8%

333,667

$5.49

16.0%

337,333

$5.49

16.2%

337,333

$5.49

16.2%

2012

2013

2014

(1)

As of January 31, 2012. 31

Adjusted Net Income (1) (In Thousands) Reconciliation of Net Income Available to Common Shareholders to Adjusted Net Income Available to Common Shareholders

Net Income Available to Common Shareholders Cash Premium on Induced Conversion Adjustments Net of Tax: Amortization of Deferred Gain on Sale (Gain) Loss on Sale of Properties Impairment Expense Loss on Early Extinguishment of Debt Unrealized Derivative (Gains) Losses Adjusted Net Income (1) Adjusted Net Income Available to Common Shareholders per Share, Basic (2) Adjusted Net Income Available to Common Shareholders per Share, Diluted (2) (1)

(2)

Three Months Ended December 31, 2011 2010 $ 62,620 $ 65,925 -

Twelve Months Ended December 31, 2011 2010 $ 490,610 $ 272,683

47,529

(2,227) (1,012) 8,869 56,273 $ 124,523

(2,521) 334 9,119 26,137 $ 98,994

(8,781) (10,278) 24,435 (39,751) $ 456,235

(9,708) (863) 16,492 3,877 (25,329) $ 304,681

1.06

0.85

3.89

2.99

1.05

0.84

3.85

2.71

Adjusted Net Income Available to Common Shareholders is a non-GAAP financial measure. Management believes it provides useful information to investors for analysis of Whitingâ&#x20AC;&#x2122;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. All per share amounts have been retroactively restated for the 2010 periods to reflect the Companyâ&#x20AC;&#x2122;s two-for-one stock split in February 2011.

Discretionary Cash Flow (1) Reconciliation of Net Cash Provided by Operating Activities to Discretionary Cash Flow (In Thousands) Three Months Ended December 31, 2011

2010

2011

2010

$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)

Net cash provided by operating activities

Changes in working capital Preferred stock dividends paid Discretionary cash flow

(1)

Twelve Months Ended December 31,

(1)

(8,496)

(5,555)

10,762

(60,545)

(269)

(1,077)

(16,441)

$328,809

$277,160

$1,242,705

$949,330

Discretionary cash flow is computed as net income plus exploration and impairment costs, depreciation, depletion and amortization, deferred income taxes, noncash interest costs, losses on early extinguishment of debt, non-cash compensation plan charges, non-cash losses on mark-to-market derivatives and other noncurrent 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 Companyâ&#x20AC;&#x2122;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.

Guidance for Q1 and Full-Year 2012(1)

Guidance First Quarter Full-Year 2012 2012 6.80 7.20 28.30 29.70

Production (MMBOE) ................................................ 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

Prod. taxes (% of production revenue) ..................... Oil price differentials to NYMEX per Bbl ..................... Gas price premium to NYMEX per Mcf

(1)

...................

7.8% -

$ 20.50 - $ 20.90

8.0%

7.9% -

8.2%

($13.00) - ($14.00)

($10.50) - ($11.50)

0.60 - $

0.90

0.60 - $

0.90

Includes the effect of Whitingâ&#x20AC;&#x2122;s fixed-price gas contracts. Please refer to fixed-price gas contracts later in this presentation. (1)