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Whiting Petroleum Corporation Current Corporate Presentation September 2013


Forward Looking Statements, Non-GAAP Measures, Reserve and Resource Information 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 forwardlooking 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 forwardlooking statements include the Company’s business strategy, financial strategy, oil and natural gas prices, production, reserves and resources, 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.

2


Whiting Overview

Q2 2013 Production(1)

93.4 MBOE/d +16% YoY +4.8% QoQ

Proved Reserves(2)

378.8 MMBOE

% Oil(2)

80%

R/P ratio(3)

13 years

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

(1) The production attributable to the Postle field, which was sold on July 15, 2013, was 7.6 MBOE/d for the three months ended June 30, 2013. (2) Whiting reserves at December 31, 2012 based on independent engineering. (3) R/P ratio based on year-end 2012 proved reserves and 2012 production.

3


Map of Operations

Michigan 2.2 MBOE/D

ROCKY MOUNTAINS 69.9 MBOE/D

Q2 2013 Net Production 93.4 MBOE/d (1) 12% 13%

HEADQUARTERS Denver, Colorado

Mid-Con(1) 7.8 MBOE/D

75%

PERMIAN 11.9 MBOE/D

Gulf Coast 1.6 MBOE/D

Rockies

Permian

Others

(1) The production attributable to the Postle field, which was sold on July 15, 2013 and located in the Mid-Con region, was 7.6 MBOE/d for the three months ended June 30, 2013.

4


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

378.8 MMBOE Proved Reserves(1) (12/31/2012) 13%

2% 1%

51% 33%

Rocky Mountains

Permian Basin

Michigan

Gulf Coast

Mid-Continent

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

5


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

3P Reserves (1)

Proved Probable Possible

(1)

Oil (MMBbl)

NGLs (MMBbl)

301.3 85.0 123.2

40.1 11.9 21.9

Natural Gas Total (Bcf) (MMBOE) 224.3 109.6 156.4

378.8 115.2 171.2

% Oil

Pre-Tax PV10% Value (In MM)

% Total

80% 74% 72%

$7,284(2) $1,262(3) $1,359(3)

73% 13% 14%

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


Postle Sale: $860 MM – A Transforming Transaction • $850 million net to Whiting • Whiting operates until Oct. 31, 2013 • This transforming transaction allows us to deploy more capital to our development areas in the Northern Rockies, Central Rockies and Permian Basin. • $2.15 billion bank credit commitment after sale 2013 CAPEX Changes $MM

New Drilling in Northern Rockies New Drilling in Permian Basin Non-Operated Drilling New Drilling at Redtail (1) Land New Drilling in Gulf Coast Exploration Expense Downward Adjustments (2)

$161 75 36 30 30 25 3 (60) $300

(1) A third rig is scheduled to arrive at Redtail in the fourth quarter. Therefore, a larger capex impact is anticipated in 2014. (2) Consists of $33 million downward adjustment for facilities and $27 million downward adjustment for EOR projects due to the sale of the Postle field assets.

7


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

Exploration Expense (2) $85 MM

Facilities (3) Well Work, Misc. Costs, Other $145 MM $150 MM

Land $138 MM

Northern Rockies $1,303 MM

2013 CAPEX Gross Net (MM) Wells Wells $1,303 247 167

Northern Rockies EOR

Non-Operated $200 MM

213

Permian Central Rockies

Gulf Coast $25 MM

Gulf Coast Non-Operated Land Exploration Expense

Central Rockies $166 MM Permian $75 MM

Facilities

(2)

(3)

Well Work, Misc. Costs, Other EOR $213 MM

Total Budget

NA(1)

% of Total 52%

NA(1)

8%

75

7

7

3%

166

43

32

7%

25

3

3

1%

200

8%

138

6%

85

3%

145

6%

150

6%

$2,500

300

209 100%

(1)These

multi-year CO2 projects involve many re-entries, workovers and conversions. Therefore, they are budgeted on a project basis and not a well basis. of exploration salaries, seismic activities and delay rentals. (3) Includes capital reduction from Postle sale. (2)Comprised

8


Drilling Inventory Identified Primary Locations Northern Rockies Southern Williston (Lewis & Clark; Pronghorn) Western Williston(1) (Cassandra; Hidden Bench; Tarpon; Missouri Breaks) Sanish (Sanish; Parshall) (2) Other (3) Total Central Rockies Redtail Niobrara Other (4) Total Gulf Coast Mid-Cont Permian Basin (5) Michigan Total Primary Inventory Identified Prospective Locations Williston Basin Williston Basin New Objectives Missouri Breaks Upper Three Forks Hidden Bench Lower Bakken Silt / Higher Density Pilot Cassandra Lower Three Forks Tarpon Lower Three Forks Total Williston Basin Higher Density Locations Pronghorn Sand Higher Density Sanish Higher Density and Infill Total Williston Basin Total Prospective Locations Permian Basin Big Tex Horizontal Total Prospective Inventory Total Potential Locations (6)

Gross 1,104 1,174 260 588 3,126

Net 410.2 380.5 118.1 340.3 1,249.1

Wells per Spacing Unit 3 Pronghorn Sand / 1280 4 Middle BKN; 3 Upper TFK / 1280 3.5 Middle BKN; 3 Upper TFK / 1280

2,420 958 3,378 131 41 817 63 7,556

1,215.7 654.1 1,869.8 98.1 33.7 319.3 53.3 3,623.3

8 Nio "B"; 4 Nio "A" / 640 - 960

Gross 321 556 120 40 1,037

Net 102.8 161.9 40.0 15.0 319.7

Wells per Spacing Unit 3 Upper TFK / 1280 4 BKN Silt; 4 Middle BKN per 1280 4 Lower TFK per 1280 3 Lower TFK per 1280

453 191 644 1,681

167.3 175.9 343.2 662.9

3 Add'l Pronghorn Sand / 1280 3 Add'l Middle BKN / 1280

424 2,105 9,661

217.0 879.9 4,503.2

6 Upper Wolfcamp / 640

(1) Tarpon

primary development on 3 Middle BKN; 2 Upper TKS due to high natural fracturing. Excludes Upper TFK at Missouri Breaks. 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. (2) Cross

9


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

B Zone

A B C D

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

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

10


Sanish Field Infill Resource Estimate OOIP by Zone Middle Bakken

MMBOE/1280* 6 7 6 11** 30

A Zone B Zone C Zone D Zone Total Middle Bakken Total Bakken Shale*** Three Forks Grand Total

19 9 58

Middle Bakken Recoverable Oil per Well (At 30 MMBOE/DSU) 4 wells 10% Recovery (Current Design)

7 wells 15% Recovery

7 wells 20% Recovery

0.74

0.66

0.85

* Assumes fieldwide average with constant GOR (1000 MCF/BO) ** Whiting believes the D zone is underexploited. Note the 11 MMBOE OOIP per DSU. *** Bakken Shale recovery efficiencies is generally considered < 2%

11


Williston Basin Primary and Prospective Drilling Plan by Area

12


Whiting Lease Areas in Williston Basin

Sanish

Field

Target

Gross Acres

Net Acres

Sanish / Parshall

Middle Bakken / Three Forks

175,066

82,406

Pronghorn

Pronghorn Sand

196,515

128,596

Lewis & Clark

Three Forks

198,926

134,034

Hidden Bench

Middle Bakken / Three Forks

47,963

29,217

CASSANDRA

STARBUCK

SANISH & PARSHALL

New Acquisition MISSOURI Acreage BREAKS

TARPON

8,805

6,258

Starbuck

Middle Bakken / Three Forks Middle Bakken / Three Forks / Red River

104,144

89,815

Missouri Breaks

Middle Bakken / Three Forks

84,213

57,526

Cassandra

Middle Bakken / Three Forks

30,427

13,951

Big Island

Red River

175,664

126,795

74,783

28,661

1,096,506

697,259

39,310

17,282

1,135,816

714,541

Tarpon

HIDDEN BENCH

LEWIS & CLARK

Other ND & Montana

BIG ISLAND

New Acquisition Acreage Outline

Pronghorn (1)

Middle Bakken / Three Forks

(1)

As of 6/30/13, Whitingâ&#x20AC;&#x2122;s total acreage cost in 697,259 net acres is approximately $383 million, or $549 per net acre.

13


Southern Williston Basin Lewis & Clark and Pronghorn (June 30, 2013) Planned Higher Density Pilot Locations

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

ACREAGE Whiting has assembled 395,441 gross (262,630 net) acres in our Southern Williston Basin.

LEWIS & CLARK

• 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.

BIG ISLAND

Pronghorn

14


Western Williston Basin Cassandra, Hidden Bench, Tarpon, and Missouri Breaks (June 30, 2013) OBJECTIVE(1)

Planned Higher Density Pilot Locations

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

STARBUCK CASSANDRA

ACREAGE Whiting has assembled 171,408 gross (106,952 net) acres in our Western Williston Basin.

TARPON

• 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

MISSOURI BREAKS

We believe higher density drilling could improve our recovery efficiency in the Middle Bakken reservoir in Hidden Bench. HIDDEN BENCH

New Missouri Breaks completion design has yielded strong results. (1)

Tarpon primary development on 3 Middle BKN; 2 Upper TKS due to high natural fracturing. Excludes Upper TFK at Missouri Breaks.

15


Sanish Area Sanish and Parshall Fields (June 30, 2013) OBJECTIVE

Planned Higher Density Pilot Locations

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

ACREAGE Whiting has assembled 175,066 gross (82,406 net) acres in our Sanish and Parshall fields.

PARSHALL

• Average WI of 47% • Average NRI of 39% • Well by well WI and NRI will vary based on ownership in each spacing unit

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

DRILLING HIGHLIGHTS Initiated high density pilot. Downspacing 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.

16


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

BIG ISLAND Whiting has assembled 175,664 gross (126,795 net) acres in our Big Island development project: • 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 104,144 gross (89,815 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 84,213 gross (57,526 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 Plienis 24-24 producing 471 BOEPD.

17


Williston Basin Production Profile Range of Reserves: Bakken / Pronghorn Sand / Three Forks (1)(2) EUR - 600 MBOE , Development Phase CAPEX $7.5 MM

Equivalent Daily Production BOE/D

1,000

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 EUR – 600 MBOE

100

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

EUR – 400 MBOE

10 0

20

40

60

80

100

120

140

160

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 pre-tax PV10% values do not purport to 18 present the fair value of our oil and natural gas reserves. EURs, ROIs, IRRs and PV10% values will vary well to well. Estimates updated as of December 31, 2012.


NDPA Williston Basin Oil Production & Export Capacity

(1)

BOPD

May 2013 Production 877,563 BOPD(2)

(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


Plants / Pipeline Williston Basin â&#x20AC;&#x201C; Natural Gas Processing Plants (Robinson Lake)

SANISH FIELD

Gathering System Oil Gathering Lines Gas Gathering Lines Current Wells Connected (Op.) Current Wells Connected (Non-Op.) Total Current Wells Connected Est. Ultimate Wells Connected

121 Miles 363 Miles 313 387 700 1,538

Robinson Lake Gas Plant Volume (7/15/13)

73 MMcfd

Planned Capacity (1) Processing Compression Fractionator Capital Investment (2) Oil Gathering/Terminal Gas Gathering Robinson Lake Gas Plant Total

90 MMcfd 80 MMcfd 310 Mgpd

$25 MM 36 MM 72 MM $133 MM

Estimated 2013 Annual Operating Cash Flow (2)

(1)

$40 MM

Planned capacity through 2013 presented pertain to Whiting's 50% Ownership

(2) Values

20


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

Planned Gathering System Oil Gathering Lines

143 Miles

Gas Gathering Lines

137 Miles

Current Wells Connected (12/31/12 – Op.) Current Wells Connected (12/31/12 – Non-Op.) Total Current Wells Connected Ultimate Wells Connected (Op & Non)

80 5 85 310

Pronghorn Field Belfield Gas Plant Volume (7/15/13)

13 MMcfd

Planned Capacity (1) Processing

30 MMcfd

Compression

24 MMcfd

Capital Investment (2) Oil Gathering/Terminal Gas Gathering Belfield Gas Plant Total

Estimated 2013 Annual Operating Cash Flow (2)

Built Planned

$29 MM 23 MM 34 MM $86 MM

$20 MM

(1) Planned capacity through 2013 (2) Capital Investment and Net Income pertain to 50% ownership

Built Planned

21


Redtail Niobrara Prospect: Another Transformative Multi Year Project Weld County, Colorado (June 30, 2013) 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”

Wildhorse 04-0424H 100% WI 3,657’ lateral 24 stages Flowed 731 BOEPD (30.5 BOEPD/stage) 7/28/13

Razor 33-2813H 59% WI 6,047’ lateral 32 stages IP: 1,069 BOEPD (33.4 BOEPD/stage) 7/9/2013

ACREAGE Whiting has assembled 120,513 gross (87,559 net) acres in our Redtail prospect in the northeastern portion of the DJ Basin. • Average WI of 73% • Average NRI of 59% Subsequent to 2Q acquired 42,821 gross (32,506 net) acres. Approximately 50% of the gross/net acres lie in the core of our Redtail Prospect. Including this transaction, the average acquisition price for the Redtail Prospect equals $431 per net acre. COMPLETED WELL COST Horizontal: $4 MM to $5.5 MM

Industry Horizontal Wells Whiting Horizontal Wells Whiting Lease Area Noble Acreage Vertical Production Trends

General trend of Colorado Mineral Belt Acreage added post second quarter

DRILLING HIGHLIGHTS Recently completed the Wildhorse 040424H flowing 731 BOEPD and the Razor 33-2813H flowing 1,069 BOEPD from the Niobrara “B” formation. Currently have two rigs drilling and plan to add a third 22 rig in October.


Redtail Resource Potential Niobrara A&B Reservoirs Niobrara Reservoir

Niobrara Resource Potential

Whiting RAZOR 25-2514H GR 0 10

Zone 200

PHI 30

Mineralogy -10

BVFluid 0

RES 0.2

OOIP by Zone

2000

Reservoir Porosity Thickness OOIP (% ) (ft) (MMBOE/960ac)*

A

NIO A NIO B NIO C

13% 13% 11%

35 65 25

Total A Zone + B Zone**

19 40 11 59

B Recoverable Oil per Well (At 59 MMBOE/DSU)

C

16 wells 10% Recovery 0.37

16 wells 15% Recovery 0.56

16 wells 20% Recovery 0.74

* GOR=500 cf/bo ** Stimulated Rock Volume 23


Redtail Niobrara Prospect Improved Completion Technology Results in Improved Performance Cum BOE* 60,000

50,000

40,000

30,000

20,000

400 MBOE Type Curve Cum vs Time 10,000

7 Recent Well Average Cum vs Time 0 0

30 * 700 SCF/ STB GOR

60

90

120

150

180

210

Days on Production 24


Big Tex Prospect Pecos, Reeves, and Ward Counties, Texas (June 30, 2013)

OBJECTIVE Vertical Wolfbone Hz. Wolfcamp ACREAGE Whiting has assembled 93,207 gross (69,221 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.

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

LeGear 11-02H IP: 478 BOE/D

May 2501 IP: 353 BOE/D Big Tex North 301H IP: 440 BOE/D Vertical Wolfcamp Discovery Wells Horizontal Wolfcamp Discovery Wells

Stewart 101 IP: 232 BOE/D

COMPLETED WELL COST Horizontal Development: $8.5 MM - $9 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 7 Upper Wolfcamp wells in 2013.

25


EOR Project North Ward Estes Field Development Plan Project Timing and Net Reserves(1) CO2 Project

Injection Start Date

Base: Primary, WF & CO2

Other Proved

P2

P3

Total

42

16

4

66

128

Phase 1

2007 - 2014

0

1

1

1

3

Phase 2

2009 - 2019

0

1

1

3

5

Phase 3

2010 - 2025

0

20

4

7

31

Phase 4

2013 - 2025

0

3

1

1

5

Phase 5

2013 - 2027

0

3

8

9

20

Phase 6

2016 - 2030

0

11

2

3

16

Phase 7

2018 - 2031

0

4

1

1

6

Phase 8

2019 - 2032

0

2

0

1

3

Totals

42

61

22

92

217

(MMBOE)

60,547 Net Acres

PVPD

(1)

Oil and gas reserve quantities are based on YE 2012 engineering update.

26


Consistently Good Margins

Consistently Delivering Strong EBITDA Margins (1) Oil $89.15/Bbl NGL $37.80/BOE Gas $4.27/Mcf

Whiting Realized Prices(1) $/BOE

$80.00

$73.88

$69.06

$70.00 $60.00

$69.85

$74.77 $75.88/BOE

$61.48 $53.57

$50.00

$50.88/67% $50.65/68% $46.16/66% $49.98/67%

$45.01

$45.10/65%

$41.58/68%

$40.00

$31.29/58%

$30.00 $20.00 $10.00

3% 5% 7%

27%

$25.71/57% 3% 5% 7%

3%

5% 8%

5%

4% 5%

8%

8%

17%

18%

17%

16%

2011

2012

2%

5% 5% 7%

2% 5% 7%

5% 8%

20%

26%

18%

2008

2009

2010

3%

$0.00

2007

Lease Operating Expense

Production Taxes

(1) Includes hedging adjustments.

G&A

Q1 2013 Q2 2013

Exploration Expense

EBITDA

27


Whiting Highlights

OIL WEIGHTED, LONG-LIVED RESERVE BASE

•RESERVES: 80% OIL (1) •13 YEAR R/P(1)

MULTI-YEAR INVENTORY TO DRIVE ORGANIC PRODUCTION GROWTH

•9,661 GROSS (4,503.2 NET) POTENTIAL DRILLING LOCATIONS •PROJECT +12% YOY PRODUCTION GROWTH IN 2013

DISCIPLINED ACQUIRER WITH STRONG RECORD OF ACCRETIVE ACQUISITIONS

COMMITMENT TO FINANCIAL STRENGTH

PROVEN MANAGEMENT AND TECHNICAL TEAM

(1)

•16 ACQUISITIONS 2004-2012 •230.9 MMBOE AT $8.23 PER BOE ACQ COST •ACQUIRED 697,259 NET ACRES IN THE WILLISTON BASIN 2005-2013; $549 PER NET ACRE AVERAGE

•TOTAL DEBT TO CAP OF 38% AS OF JUN-30-13

•AVERAGE 28 YEARS EXPERIENCE

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

28

Wll september 2013  

September 2013 Corporate Presentation

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