Whiting Petroleum Corporation In the foreground is the Pronghorn Federal 21-14TFH, completed with an initial flow rate of 1,849 BOE/D. The well in the background is the Pronghorn Federal 34-11TFH, completed with an initial flow rate of 1,645 BOE/D. Both wells are located in the Pronghorn area of Stark County, N.D.
Third Quarter 2011 Financial and Operating Results November 3, 2011
Laying a 24� natural gas trunk line leading to the Belfield Gas Processing Plant in Stark County, N.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, 2010 and Form 10-Q for the quarter ended September 30, 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 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, Whitingâ€&#x;s EOR project in Ward and Winkler County, Texas.
Market Capitalization1
$5.9 B
Long-term Debt2
$1,200 MM
Shares Outstanding
117.4 MM
Debt/Total Cap2
28.9%
Proved reserves3 % Oil
304.9 MMBOE 83%
RP ratio4
12.9 years
Q3 2011 Production
70.7 MBOE/d
1
Assumes a $50.39 share price (closing price as of October 28, 2011) on 117,380,843 common shares outstanding as of September 30, 2011.
2
As of September 30, 2011. Please refer to Slide #29 for details.
3
Whiting reserves at December 31, 2010 based on independent engineering.
4
R/P ratio based on year-end 2010 proved reserves and 2010 production.
2
Map of Operations Q3 2011 Net Production 70.7 MBOE/d 4% 3%
ROCKY MOUNTAINS 43.9 MBOE/D
12% MICHIGAN 3.0 MBOE/D
18%
63%
MID-CONTINENT 8.4 MBOE/D
Michigan
Gulf Coast
Mid-Continent
Permian Basin
Rocky Mountains PERMIAN 13.0 MBOE/D
Proved Reserves at December 31, 2010 (1)
Core Area Permian Basin Rocky Mountains Mid-Continent Gulf Coast Michigan
Oil (2) (MMBbl) 115.6 94.5 38.2 3.2 2.8
Total
254.3 (2)
Gas Total (Bcf) (MMBOE) 47.9 123.6 162.8 121.6 19.9 41.5 36.9 9.4 36.0 8.8 303.5
304.9
Pre-Tax PV10%
Q3 2011 Average Daily Net
Oil % 94% 78% 92% 34% 32%
Value (1) (in millions) $1,471.5 $2,425.5 $955.2 $113.3 $78.9
Production (MBOE/d) 13.0 43.9 8.4 2.4 3.0
83%
$5,044.4
70.7
Oil includes natural gas liquids
GULF COAST 2.4 MBOE/D (1)
Based on 12-month average prices of $79.43/Bbl and $4.38/Mcf in accordance with SEC requirements. Our pre-tax PV10 values do not purport to present the fair value of our oil and natural gas reserves.
3
2011 Capital Budget – By Area ($ in millions) 2011 Capital Budget $1.7 B Land 13% $217MM
Other (1) 5% $92MM
Bakken/Three Forks Hydrocarbon System 52% $882MM
Permian 7% $117MM
EOR 18% $314MM
Central Rockies 5% $79MM (1) Comprised primarily of exploration salaries, lease delay rentals, seismic, other exploration and development and timing adjustments.
4
Breakdown of 2011 Capital Budget By Area ($ in millions) EST. 2011 CAPEX IN MM $ Gross Wells Net Wells
(1)
(2)
These multi-year CO2 projects involve many reentries, 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
Northern Rockies Sanish Parshall Lewis & Clark Cassandra Hidden Bench Starbuck Missouri Breaks Tarpon Northern Rockies Other Big Island Big Stick Total Northern Rockies EOR Projects North Ward Estes Postle Total EOR Permian Basin Big Tex Other Total Permian Central Rockies DJ Basin Other Total Central Rockies Gulf Coast Various Total Gulf Coast Michigan PDC Expl. & Dvlp Total Michigan Land Exploration Expense (2) Facilities Total Budget
355.5 4.7 311.6 24.3 68.6 18.0 0.0 4.5 10.0 20.2 8.3 825.5
105 3 48 15 32 7 0 2 25 4 5 246
53.3 0.6 35.9 2.9 8.4 2.1 0.0 0.6 1.6 3.9 3.1 112.4
142.3 77.6 219.9
NA(1)
NA(1)
66.5 44.7 111.2
15 8 23
15.0 4.5 19.5
41.8 21.4 63.2
14 6 20
8.2 5.4 13.6
7.9 7.9
6 6
3.4 3.4
9.1 9.1 216.5 48.2 198.4 1,700
2 2
1.0 1.0
297
149.9
5
All Whiting Lease Areas In Williston Basin Plays at September 30, 2011
A
CASSANDRA
1 STARBUCK 2
3 TARPON
MISSOURI BREAKS
HIDDEN BENCH
4
SANISH & PARSHALL
Sanish / Parshall - Middle Bakken / Three Forks Objectives - 108 wells in 2011 Lewis & Clark / Pronghorn - Three Forks Objective - 48 in 2011 Hidden Bench - Middle Bakken / Three Forks Objectives 32 Wells in 2011 Tarpon - Middle Bakken / Three Forks Objectives 2 wells in 2011 Starbuck - Middle Bakken / Three Forks Objectives - 7 Wells in 2011 Missouri Breaks - Middle Bakken / Three Forks Objectives Cassandra - Middle Bakken / Three Forks Objectives - 15 wells in 2011 Big Island - Multiple Objectives - 4 wells in 2011 Other ND & Montana
LEWIS 5 & CLARK
67 BIG ISLAND
Gross Acres Net Acres 177,719 83,230
384,658
255,905
59,734
29,334
8,125
6,265
103,922
88,320
58,200
40,250
30,661
14,483
164,589
121,097
115,897 1,103,505
43,955 682,839(1)
8 9 10
A‟ (1)
Whiting‟s total acreage cost in 683M net acres is approximately $288 million, or $421 per net acre.
6
Whiting Drilling Objectives in the Western Williston Basin -- Shooting for the “Sweet Spots” A‟
A
1 Area
Starbuck
2 IP
Missouri Breaks
BEXP Gobbs 17-81H
1,818 BEXP Johnson 30-191H
BEXP Swindle 16-91H
1,065
BEXP Rogney 17-81H
909
3 IP
Tarpon
2,962 Tarpon Federal 21-4H
4 IP 7009
Hidden Bench
5 IP
Rovelstad 21-13H
2450
Arnegard 21-26H
3092
Johnson 31-4H
2520
Kummer 34-31H
2216
Norgard 21-13H
3065
6
O'Neil Creek Mosser 11-27TFH
IP (3)
Beaver Creek
193 Buckhorn Ranch 31-16H
7 IP
8
Demores
IP (2)
Elkhorn Ranch
9 IP
Big Stick
10 IP
Pronghorn
Schneider 11-6TFH
MOI 22-15HCE
339
Odermann 41-31TFH
Federal 32-4H BK CE
1970
Schneider 12-12TFH
455
Ellison Creek 11-1TFH
608
Haystack 11-19TFH
379
Dry Creek 11-13TFH
906
Demores Federal 31-10TFH
789
Duletski 21-16TFH
819
Dry Creek 44-20TFH
2337
Froehlich 44-9TFH
2090
Hecker 21-18TFH
3612
Kubas 11-13TFH
1953
Lydia 21-14TFH
1960
(2)
256 Clemens 34-9TFH
2109
Teddy 44-13TFH
381
Inside Reservoir Boundary
702 Mikes Creek Federal 12-30TFH
942
Teddy 44-30TFH
1874
Brueni 28-1H
473
Teddy 21-24TFH
875
Dietz 21-17TFH
1007
Dietz 21-18TFH
881
Mann 21-18TFH Obrigewitch 21-17TFH
2,962
7,009
2,669 (3)
Weather may have caused ineffective frac.
Wolski 44-23H drilled in this area, completed in Scallion. IP 188 BOE per day.
193
1,119 (2)
Plan to change well orientation to North-South
516
1,526
1189
Richard 21-15TFH
1028
Smith 34-12TFH
2939 954
Praus 21-28TFH
405
Pronghorn Federal 34-11 TFH
1645
Pronghorn Federal 21-14TFH
1,264
Combined Avg
870 (1)
Talkington 21-30TFH
AVG IP
IP
552
1,043
1849
1,480
1,545
Outside Southwest Reservoir Boundary PALUCK 21-28TFH
239
ROLLER 21-26TFH
186
ARTHAUD 21-29TFH
269
PALUCK 21-27TFH
494
BINSTOCK 21-30TFH
310
(1)
300 Produced from only 1-2 frac stages
7
Typical Non-Sanish Field Bakken or Pronghorn Sand / Three Forks Well Expected Results 1000 EUR 350 MBOE, Capex $7.0 MM Oil Price ($/Bbl)
90.00 2.0 2.3 3.23 35%
100.00 2.3 1.9 4.57 47%
EUR 600 MBOE, Capex $7.0 MM Oil Price ($/Bbl) 90.00 ROI 3.7 Payout (yrs) 0.9 PV10 ($MM) 11.03 IRR 155%
100.00 4.2 0.8 13.28 213%
Daily Equavlent Oil Rate
ROI Payout (yrs) PV10 ($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
20
40
60
80
100
120
140
160
180
Months
8
Sanish and Parshall Fields Recent and Notable Wells Units in which WLL Owns an Interest
17-mile 6” & 10” Residue Gas/NGL Line to WBIGas sales to Midwest markets Began in late August „08
17-mile 8” Crude Oil Line To Enbridge – Initial oil sales To Midwest markets began In early December „09
PARSHALL FIELD As of 10-22-11 Parshall Field Outline
127
Current Producers Potential Operated Bakken Locations Non-Interest Wells 68,904 Gross Acres 16,662 Net Acres
NEW WELL Brehm 42-35XH (Cross Unit) IP: 1888 BOE/D 08/23/2011
NEW WELL Brehm 41-35XH (Cross Unit) IP: 1979 BOE/D 07/20/2011
Robinson Lake Gas Plant
SANISH FIELD As of 10-22-11 Sanish Field Outline
283 17 8 2 88 153
Current Producers Currently Completing Currently Drilling Remaining Operated Bakken Infill Locations Other Potential Operated Bakken Locations Potential Operated Three Forks Locations
Non-Interest Wells Refer to Slide #10 for more details. 108,815 Gross Acres 66,568 Net Acres
NEW WELL Brehm 12-7TFH IP: 1627 BOE/D 09/15/2011
NEW WELL Lacey 14-3XH (Cross Unit) IP: 1955 BOE/D 08/13/11
NEW WELL Hansen 14-20XH (Cross Unit) IP: 2893 BOE/D 8/24/2011
9
Fully Developed Bakken and Three Forks Horizontal Wells in Sanish Field Area
(1)
Represents an increase of 182 gross wells from the previous estimate of 382. Well counts and well plans will vary based upon continued evaluation. Drilling, WOC
Completed
Planned/ Potential
Total
Middle Bakken
2
136
1
139
Cross-Unit Middle Bakken
1
20
9
30
Wing - Middle Bakken
0
3
80
83
Three Forks
22
45
150
217
Total Operated
25
204
240
469
Non-Op Bakken
10
74
5
89
Non-Op Three Forks
1
5
0
6
Three Forks Non-Op Wells
Grand Total
36
283
245
564(1)
Sanish Field Outline
Parshall Field Outline
Bakken
As of October 22, 2011
10
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 October, 2011)
11
Williston Basin Off-Take Expansion (1) Existing Pipelines Proposed Pipelines
All Volumes Barrels per Day
2012
2013
Additions
Additions
Additions
Total
Enbridge
185,000
25,000 Q2
145,000 Q4
Bridger / Belle Fourche
120,000
30,000 Q3
50,000 Q1
Tesoro /Mandan
60,000
EOG (rail)
60,000
100000 Q1
300,000 60,000 60,000
50,000 Q4
50,000
Hess (rail)
60,000 Q1
60,000
COLT (rail)
27,000 Q2
27,000
100,000 Q3
200,000
90,000 Q2
90,000
100,000 Q3
Savage (rail)
90000 Q1
Quintana (rail) Total
355,000
Plains
BOE(Lario) (rail)
TransCanada Keystone XL
2011 Existing Capacity
425,000
155,000
(1) Projected additions based on publicly available knowledge.
522,000
190,000
90,000 1,292,000
12
Average IP and 30, 60, 90 Day Production(1) of Whiting Operated Wells Sanish Bakken
No. of Wells Averages
Avg WI % 30 68%
Avg NRI % 30 55%
Avg IP BOE/d 24-hr Test 30 2,035
Avg 1st 30 Day 28 760
Avg 1st 60 Day 24 648
Avg 1st 90 Day 16 528
Avg 1st 60 Day 7 281
Avg 1st 90 Day 4 288
Avg 1st 60 Day 23 404
Avg 1st 90 Day 21 387
Avg 1st 60 Day 2 627
Avg 1st 90 Day 2 548
Sanish Three Forks
No. of Wells Averages
Avg WI % 33 65%
Avg NRI % 33 52%
Avg IP BOE/d 24-hr Test 33 817
Avg 1st 30 Day 16 383
Lewis & Clark / Pronghorn
No. of Wells Averages
Avg WI % 33 77%
Avg NRI % 33 62%
Avg IP BOE/d 24-hr Test 33 1,192
Avg 1st 30 Day 29 523
Hidden Bench
No. of Wells Averages
(1)
Avg WI % 5 63%
Avg NRI % 5 50%
Based on actual days on production
Avg IP BOE/d 24-hr Test 5 2,669
Avg 1st 30 Day 4 694
13
De-Risked Map – Williston Basin (1) CASSANDRA
STARBUCK 103,922 Prospect Gross Acres 88,320 Prospect Net Acres
30,661 Prospect Gross Acres 14,483 Prospect Net Acres 100% De-Risked
SANISH 108,815 Prospect Gross Acres 66,568 Prospect Net Acres 100% De-Risked
TARPON 8,125 Prospect Gross Acres 6,265 Prospect Net Acres 100% De-Risked
PARSHALL 68,904 Prospect Gross Acres 16,662 Prospect Net Acres 100% De-Risked
MISSOURI BREAKS 58,200 Prospect Gross Acres 40,250 Prospect Net Acres
HIDDEN BENCH 59,734 Prospect Gross Acres 29,334 Prospect Net Acres 100% De-Risked
Bakken Pinch-Out LEWIS & CLARK 216,240 Prospect Gross Acres 139,551 Prospect Net Acres 100,041 De-Risk Gross Acres (46%) 64,193 De-Risk Net Acres
PRONGHORN 168,418 Prospect Gross Acres 116,354 Prospect Net Acres 99,405 De-Risk Gross Acres (59%) 68,649 De-Risk Net Acres
Whiting Williston Basin Unconventional Prospects September 30, 2011 Whiting Prospect Areas
BIG ISLAND 164,589 Prospect Gross Acres 121,097 Prospect Net Acres 640 De-Risk Gross Acres (<1%) 621 De-Risk Net Acres
Whiting De-Risked Areas To Date Whiting Interest Spacing Units (1) Whiting
unconventional acreage totals 682,839 net acres 14
De-Risked Map â&#x20AC;&#x201C; Lewis & Clark Golden Valley and Billings Counties, North Dakota
46%
1st 30 Day Avg BOEPD for wells drilled 2000 thru 2009 1st 30 Day Avg BOEPD for wells drilled 2009 thru 2011
15
De-Risked Map â&#x20AC;&#x201C; Pronghorn Billings and Stark Counties, North Dakota
59%
1st 30 Day Avg BOEPD for wells drilled 2000 thru 2009 1st 30 Day Avg BOEPD for wells drilled 2009 thru 2011
16
De-Risked Map â&#x20AC;&#x201C; Hidden Bench McKenzie County, North Dakota
100%
1st 30 Day Avg BOEPD for wells drilled 2000 thru 2009 1st 30 Day Avg BOEPD for wells drilled 2009 thru 2011
17
De-Risked Map â&#x20AC;&#x201C; Tarpon McKenzie County, North Dakota
100%
1st 30 Day Avg BOEPD for wells drilled 2000 thru 2009 1st 30 Day Avg BOEPD for wells drilled 2009 thru 2011
18
De-Risked Map â&#x20AC;&#x201C; Cassandra Williams County, North Dakota
100%
1st 30 Day Avg BOEPD for wells drilled 2000 thru 2009 1st 30 Day Avg BOEPD for wells drilled 2009 thru 2011
19
Big Tex Prospect Pecos, Reeves and Ward Counties, Texas OBJECTIVE Bone Spring Wolfcamp ACREAGE Whiting has assembled 121,771 gross (89,852 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: $2 MM Horizontal: $4.5 MM Whiting‟s first horizontal well, the Bissett 9701 is currently producing 243 BOE/d. DRILLING PROGRAM 2 rigs currently active in the area. Plan to drill 15 wells in 2011. Planned budget for the prospect in 2011 is $66.5 MM
20
Redtail Niobrara Prospect Weld County, Colorado OBJECTIVE Niobrara Shale ACREAGE Whiting has assembled 104,425 gross (76,065 net) acres in our Redtail prospect in the northeastern portion of the DJ Basin Redtail
Recent and Future Redtail Wells Well Name Wild Horse 16-13H Two Mile Creek 22-13H Sidney Draw 6-33M Sidney Draw 6-13H Runway 23-41H Horsetail 18-0733
WI / NRI Well Type 100% / 80% Horizontal 96% / 77% Horizontal 100% / 80% Monitor 100% / 80% Horizontal 100% / 80% Horizontal 100% / 80% Horizontal
Well Status Pumping 328 BOE/d IP 216 BOE/d SPUD Q3 SPUD Q3 SPUD Q4 SPUD Q4
76,065 Net Acres
. .
Two Mile Creek 22-13H
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 The Wild Horse 16-13H is currently producing 328 BOE/d. The Two Mile Creek 22-13H was completed with an IP of 216 BOE/d. Planned budget in 2011 is $41.8MM for 14 wells and facilities.
General trend of Colorado Mineral Belt
21
EOR Projects - Postle and North Ward Estes Fields
Whiting
Postle N. Ward Estes
Total Whiting
% Postle N. Ward Estes
12/31/10 Proved Reserves Oil – MMBbl Gas – Bcf Total – MMBOE
130 276 177
124 27 (1) 128
254 304 305
74%
96%
83%
54.3
16.4
70.7
% Crude Oil
49% 9% (1) 42%
Q3 2011 Production Total – MBOE/d (1)
23%
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
22
Postle Field - Net Production Forecasts (1) Postle Field 3P Unrisked Net Production Forecast (2) 25
20
Production Rate Mboe/d
120 - 130 MMcf/d Current CO2 Injection
15
10
P1 + P2 (no P3) 5
0
Proved Jun „05
Sept. „11
2011
2020
Magnitude and timing of results could vary. (1) (2)
Based on independent engineering by Cawley, Gillespie & Associates, Inc. at December 31, 2010. Includes ancillary fields. Please refer to Slide #1 for disclosures regarding “Reserve and Resource Information.” All volumes shown are unrisked. Production forecasts based on assumptions in December 31, 2010 reserve report. After 2020, Postle field proved reserve production is expected to decline at 8% - 11% year over year.
23
North Ward Estes - Net Production Forecasts (1) North Ward Estes 3P Unrisked Net Production Forecast (2) 25 285 - 295 MMcf/d Current CO2 Injection
20
Production Rate Mboe/d
P1 + P2 + P3 15
P1 + P2
10
Proved 5
0
Jun „05
Sept „11
2011
2020
Magnitude and timing of results could vary. (1) (2)
Based on independent engineering by Cawley, Gillespie & Associates, Inc. at December 31, 2010. Includes ancillary fields. Please refer to Slide #1 for disclosures regarding “Reserve and Resource Information.” All volumes shown are unrisked. Production forecasts based on assumptions in December 31, 2010 reserve report. After 2020, North Ward Estes field proved reserve production is expected to decline at 5% - 7% year over year.
24
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
33
Other Proved
P2
P3
Total
12
1
64
110
Phase 1
2007 - 2008
0 (2)
3
4
2
9
Phase 2
2009 - 2010
0 (2)
6
4
4
14
Phase 3
2010 - 2014
0
22
8
8
38
Phase 4
2011
0
3
1
1
5
Phase 5
2012 - 13
0
3
9
8
20
Phase 6
2015
0
10
4
3
17
Phase 7
2016
0
0
0
6
6
Phase 8
2016
0
0
0
3
3
Totals
33
59
31
99
222
(MMBOE)
58,000 Net Acres
PVPD
(1)
(1) Based on independent engineering at Dec. 31, 2010. Please refer to Slide #1 for disclosures regarding “Reserve and Resource Information.” All volumes shown are unrisked. (2) Response moved to Base.
25
Whiting Estimated Oil Recovery Type Curve from CO2 Flood - North Ward Estes (1)
P1 + P2
P1
(P3) (P2) (P1)
(1)
Whiting currently estimates a 15% recovery factor in arriving at its total for proved, probable and possible reserve potential. The Company is conducting tests to ascertain if additional oil may be recoverable.
26
Adjusted Net Income and Discretionary Cash Flow for the Three Months Ended September 30, 2011 and 2010 (1)(2)(3)
Three Months Ended 9/30/2011
9/30/2010
Nine Months Ended 9/30/2011
9/30/2010
(In millions, expect per share data) Net Income
$
206.0
$
5.6
$
428.0
$
206.8
Adjusted Net Income
$
112.9
$
71.6
$
332.9
$
206.3
Adjusted Earnings Per Basic Share
$
0.96
$
0.70
$
2.84
$
2.02
Adjusted Earnings Per Diluted Share
$
0.95
$
0.65
$
2.81
$
1.88
Discretionary Cash Flow
$
316.5
$
229.5
$
913.9
$
672.2
(1)
Please refer to slide #35 for a Reconciliation of Net Income Available to Common Shareholders to Adjusted Net Income Available to Common Shareholders.
(2)
Please refer to slide #36 for a Reconciliation of Net Cash Provided by Operating Activities to Discretionary Cash Flow. All per share amounts have been retroactively restated for the 2010 period to reflect the Companyâ&#x20AC;&#x;s two-for-one stock split in February 2011.
(3)
27
Consistently Strong Margins Consistently Delivering Strong EBITDA Margins (1) $80.61/Bbl $5.02/Mcf
Whiting Realized Prices(1) $/BOE
$80.00
$71.80/BOE
$69.06
$61.48
$70.00 $60.00
$50.52 $44.70
$50.00 $40.00
$45.10/65%
$35.23 $30.82/61% $28.73/64%
$27.50
$30.00
$22.91/65%
$20.00 $16.22/59% $10.00
$53.57
3% 6% 7%
4% 5% 6%
$45.01
$49.54/69%
$41.58/68%
$31.29/58%
$25.71/57% 3% 5% 7%
3% 5% 7%
5% 5% 7%
5% 7%
2% 5% 7%
2%
2% 8% 6% 25%
2% 7% 6% 20%
20%
24%
27%
20%
26%
18%
17%
2003
2004
2005
2006
2007
2008
2009
2010
Q3 11
$0.00 Lease Operating Expense
Production Taxes
(1) Includes hedging adjustments.
G&A
Exploration Expense
EBITDA
28
Total Capitalization ($ in thousands) Sept. 30, 2011
Cash and Cash Equivalents
$
6,088
Dec. 31, 2010
$
18,952
Long-Term Debt: Credit Agreement Senior Subordinated Notes Total Long-Term Debt
$ 600,000 600,000 $1,200,000
$ 200,000 600,000 $ 800,000
Stockholdersâ&#x20AC;&#x; Equity Total Capitalization Total Debt / Total Capitalization
2,955,718 $4,155,718 28.9%
2,531,315 $3,331,315 24.0%
29
Outstanding Bonds and Credit Agreement Ratings Amount Outstanding Moody‟s / S&P
11/2/11 Price
Coupon / Description
Maturity
7.00% / Sr. Sub. – NC
02/01/2014
$250.0 mil.
Ba3 / BB
107.00
6.50% / Sr. Sub. – NC4
10/01/2018
$350.0 mil.
Ba3 / BB
103.00
●
Bond Finance Covenant: Ratio of pre-tax earnings to fixed charges (interest expense) must be greater than 2:1. It was 13.96:1 at 09/30/11.
●
Restricted Payments Basket: Approximately $2.0 billion.
●
Bank Credit Agreement size is $1.5 billion (increased from 1.1 billion on 10/12/11) under which $600 million was drawn as of 09/30/11. Interest rate is currently 2.36% (LIBOR + 2.00%). Redetermination date is 5/1/12.
●
Bank Credit Agreement Covenants: Total debt to EBITDAX at 09/30/11 was 0.96:1 (must be less than 4.25:1) Working capital at 09/30/11 was 1.79:1 (must be greater than 1:1)
30
Guidance for Q4 and Full-Year 2011
Guidance Full-Year
2011
2011
6.85 -
Production (MMBOE)
7.25
25.15 -
25.55
Lease operating expense per BOE
$11.40 - $11.70
$11.90 - $12.10
General and admin. expense per BOE
$ 3.45 - $ 3.65
$ 3.35 - $ 3.55
Interest expense per BOE
$ 2.30 - $ 2.50
$ 2.35 - $ 2.55
Depr., depletion and amort. per BOE
$19.00 - $19.40
$18.60 - $19.00
Prod. taxes (% of production revenue)
(1)
Fourth Quarter
7.6% -
7.9%
7.3% -
7.6%
Oil price differentials to NYMEX per Bbl
$ 9.00 - $10.00
$ 9.50 - $10.50
Gas price premium to NYMEX per Mcf
$ 0.70 - $ 1.00
$ 0.60 - $ 0.90
(1)
Includes the effect of Whitingâ&#x20AC;&#x2122;s fixed-price gas contracts. Please refer to fixed-price gas contracts on slide #33.
31
Disciplined Hedging Strategy (1)
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
Existing Natural Gas Hedge Positions Weighted Average
As a Percentage of
Hedge
Contracted Volume
NYMEX Price Collar Range
September 2011
Period
(MMBtu per Month)
(per MMBtu)
Gas Production
34,554
$7.00 - $14.25
1.6%
Q1
33,381
$7.00 - $15.55
1.5%
Q2
32,477
$6.00 - $13.60
1.5%
42.9%
Q3
31,502
$6.00 - $14.45
1.4%
$61.90 - $105.47
42.8%
Q4
30,640
$7.00 – $13.40
1.4%
290,000
$47.67 - $90.21
16.4%
290,000
$47.67 - $90.21
16.4%
Q3
290,000
$47.67 - $90.21
16.4%
Oct
290,000
$47.67 - $90.21
16.4%
Nov
190,000
$47.22 - $85.06
10.7%
Contracted Volume (Bbls per Month)
Weighted Average NYMEX Price Collar Range (per Bbl)
As a Percentage of September 2011 Oil Production
904,255
$61.00 - $98.31
51.1%
Q1
759,054
$61.91 - $105.49
42.9%
Q2
758,850
$61.91 - $105.49
42.9%
Q3
758,650
$61.90 - $105.48
Q4
758,477
Q1 Q2
Hedge Period
2011
2011 Q4 2012
Q4
2012
2013
(1)
As of October 21, 2011.
32
Fixed-Price Marketing Contracts
Existing Natural Gas Marketing Contracts Contracted Volume (MMBtu per Month)
Weighted Average Contracted Price (per MMBtu)
As a Percentage of September 2011 Gas Production
772,460
$5.30
34.7%
Q1
577,127
$5.30
26.0%
Q2
461,460
$5.41
20.8%
Q3
465,794
$5.41
20.9%
Q4
398,667
$5.46
17.9%
Q1
360,000
$5.47
16.2%
Q2
364,000
$5.47
16.4%
Q3
368,000
$5.47
16.5%
Q4
368,000
$5.47
16.5%
Q1
330,000
$5.49
14.8%
Q2
333,667
$5.49
15.0%
Q3
337,333
$5.49
15.2%
Q4
337,333
$5.49
15.2%
Hedge Period 2011 Q4 2012
2013
2014
33
In Summary
Geographically diversified, longlived reserve base
Five core regions; 12.9 (1) year R/P
Grown proved reserves 325% from 71.7 MMBOE at Nov. 2003 IPO to 304.9 MMBOE at 12/31/10
Multi-year inventory of development, exploitation and exploration projects to drive organic production growth going forward
Grown production 315% from 17.0 MBOE/D at Nov. 2003 IPO to 70.7 MBOE/D in Q3 2011
Drilling inventory 4,600 wells at 12/31/10. (2,200 gross operated wells based on 3P reserves plus over 2,400 additional gross operated wells based on resource potential)
Additional exploration potential in the Rockies, Permian Basin and Gulf Coast
Significant organic growth potential from drilling programs
Continued moderate risk organic growth potential from North Ward Estes field
Other exploration includes horizontal oil prospects (Williston and Permian Basin)
Disciplined acquirer with strong record of accretive acquisitions
16 acquisitions in 2004 – 2010; 230.9 MMBOE at $8.23 per BOE average acquisition cost
Commitment to financial strength
Total Debt to Cap of 28.9% as of September 30, 2011
Proven management and technical team
Average 28 years of experience
(1)
R/P ratio based on year-end 2010 proved reserves and total 2010 production.
34
Adjusted Net Income (1) (In Thousands) Reconciliation of Net Income (Loss) Available to Common Shareholders to Adjusted Net Income (Loss) 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 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 September 30, 2011 2010 $ 205,966 $ 5,612 47,529
$
(2,183) (8,379) 5,881 (88,406) 112,879
Nine Months Ended September 30, 2011 2010 $ 427,990 $ 206,759 47,529
$
(2,390) 2,699 3,866 14,275 71,591
$
(6,572) (9,261) 15,666 (94,953) 332,870
$
(7,197) (1,189) 7,471 3,866 (50,951) 206,288
$
0.96
$
0.70
$
2.84
$
2.02
$
0.95
$
0.65
$
2.81
$
1.88
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 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 period to reflect the Company’s two-for-one stock split in February 2011.
35
Discretionary Cash Flow (1) Reconciliation of Net Cash Provided by Operating Activities to Discretionary Cash Flow (In Thousands)
Net cash provided by operating activities Exploration Exploratory dry hole costs Changes in working capital Preferred stock dividends paid Discretionary cash flow
(1)
(1)
Three Months Ended
Nine Months Ended
September 30,
September 30,
2011
2010
2011
2010
$275,536
$280,134
$863,754
$720,267
9,440
6,146
36,406
25,861
-417
-199
-4,714
-2,796
32,246
-51,238
19,258
-54,990
-269
-5,391
-808
-16,172
$316,536
$229,452
$913,896
$672,170
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 GAAP and may not be comparable to other similarly titled measures of other companies.
36