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.
Current Corporate Information February 2012
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. 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, Whiting‟s EOR project in Ward and Winkler County, Texas.
1 Assumes
Market Capitalization1
$6.0 B
Long-term Debt2
$1,200 MM
Shares Outstanding
117.4 MM
Debt/Total Cap3
28.9%
Proved reserves4 % Oil
345.2 MMBOE 86%
RP ratio5
13.9 years
Q4 2011 Production
70.7 MBOE/d
a $51.35 share price (closing price as of February 7, 2012) on 117,380,843 common shares outstanding as of September 30, 2011.
2 As
of September 30, 2011. Please refer to the “Outstanding Bonds and Credit Agreement” slide for details.
3 As
of September 30, 2011. Please refer to the “Total Capitalization” slide for details.
4 Whiting 5 R/P
reserves at December 31, 2011 based on independent engineering.
ratio based on year-end 2011 proved reserves and 2011 production.
2
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) Proved Reserves (12/31/2011) 2% 12% 2% 46%
38%
Rocky Mountains Gulf Coast Michigan ď ľ ď ľ
345.2 MMBOE (12/31/2011) 86% Oil / 14% Natural Gas
Permian Basin Mid-Continent
1)
Whiting reserves at December 31, 2011 based on independent engineering.
4
Whiting Pre-Tax PV10 Values at December 31, 2011 (1) - Using $96.19/Bbl and $4.12/Mcf Held Flat
Oil / Cond MMBO
Plant Prod MMBNGL
BCF
MMBOE
PV10, MM$
Total Proved
260
38
285
345
7,405
Total Probable
57
14
211
106
1,035
Total Possible
129
35
187
195
2,024
Total 3P Reserves
446
87
683
646
10,464
(1) Reserve estimates shown are based on independent engineering by Cawley, Gillespie & Associates, Inc. at December 31, 2011 using SEC NYMEX price assumptions of $96.19/Bbl and $4.12/Mcf. Please refer to the beginning of this presentation for disclosures regarding "Reserve and Resource Information." All volumes shown are unrisked. Our pre-tax PV10 values do not purport to present the fair value of our oil and natural gas reserves.
5
Capital Budget for Key Development Areas in 2012 ($ in millions)
Facilities $228MM Exploration 14% Expense (1) $56MM 4%
Non-Op $42MM 3%
Land $136MM 9% Central Rockies $50MM 3% Permian $60MM 4%
(1) (2)
EOR $177MM 11%
Northern Rockies $851MM 52%
2012 CAPEX (MM $)
Gross Wells
Net Wells
Northern Rockies
$
851
218
124
EOR
$
177
NA(1)
NA(1)
Permian
$
60
13
13
Central Rockies
$
50
11
11
Gulf Coast
$
-
Michigan
$
-
Non-Operated
$
42
Land
$
136
Exploration Expense (1) $
56 242
148
Facilities Total Budget
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.
$
228 1,600
6
All Whiting Lease Areas In Williston Basin Plays at December 31, 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 177,399 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 1,104,529
42,166 681,504(1)
8 9
Pronghorn
10
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.
7
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
8
De-Risked Map – Williston Basin (1) 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
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
BIG ISLAND 170,706 Prospect Gross Acres 121,885 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 681,504 net acres 9
Williston Basin De-Risked Future Drilling Locations at December 31, 2011
Gross Acreage
De-Risked % De-Risked Acreage
Formation Target
Wells Per 1280
De-Risked Wells Locations Completed
De-Risked Future Locations
Sanish Bakken
108,815
108,815
100%
Middle Bakken
4
341
234
107
Sanish Three Forks
108,815
108,815
100%
Three Forks
3
223
61
162
Lewis & Clark
215,199
98,992
46%
Pronghorn Sand
2
163
18
145
Pronghorn
170,466
101,453
60%
Pronghorn Sand
3
238
40
198
Hidden Bench
59,734
59,734
100%
Middle Bakken
2
93
32
61
Tarpon
8,125
8,125
100%
Middle Bakken
3
12
2
10
Cassandra
30,661
30,661
100%
Middle Bakken
2
48
15
33
1,118
402
716
10
Typical Non-Sanish Field Bakken or Pronghorn Sand / Three Forks Well Expected Results(1) 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 ($MM) 11.03 IRR 155%
100.00 4.2 0.8 13.28 213%
Daily Equavalent Oil Rate
ROI Payout (yrs) PV10 ($MM) IRR
100
EUR – 600 MBOE (Avg 1st 30 days 830 BOE/d)
EUR – 350 MBOE (Avg 1st 30 days 430 BOE/d)
10 0
20
40
60
80
100
120
140
160
180
Months
(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.
11
Average IP and 30, 60, 90 Day Production(1) of Whiting Operated Wells(2)
No. of Wells Averages
No. of Wells Averages
Averages No. of Wells
No. of Wells Averages
Avg WI % 31 67%
Avg WI % 44 62%
Avg WI % 38 78%
Avg WI % 6 62%
Avg NRI % 31 54%
Sanish Bakken Avg IP BOE/d 24hr Test Avg 1st 30 Day 31 28 2,018 760
Avg 1st 60 Day 24 648
Avg 1st 90 Day 16 528
Avg NRI % 44 50%
Sanish Three Forks Avg IP BOE/d 24hr Test Avg 1st 30 Day 44 16 787 383
Avg 1st 60 Day 7 281
Avg 1st 90 Day 4 288
Avg NRI % 38 63%
Lewis & Clark / Pronghorn Avg IP BOE/d 24hr Test Avg 1st 30 Day 38 33 1,333 565
Avg 1st 60 Day 28 439
Avg 1st 90 Day 24 383
Avg NRI % 6 49%
Hidden Bench / Tarpon Avg IP BOE/d 24hr Test Avg 1st 30 Day 6 5 3,392 941
Avg 1st 60 Day 3 1,040
Avg 1st 90 Day 3 930
(1) Based on actual days on production (2) January 2011 â&#x20AC;&#x201C; December 31, 2011
12
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)
13
Pronghorn Q4 2011 Completions(1)
Well Name
(1)
WI%
NRI%
IP BOEPD
PRONGHORN FEDERAL 34-11 TFH
100%
80%
1,645
PRONGHORN FEDERAL 21-14TFH
56%
45%
1,849
BRUENI 21-16TFH
60%
48%
889
MASTEL 41-18TFH
77%
61%
3,218
MARSH 21-16TFH-R
79%
63%
2,694
OBRIGEWITCH 11-17TFH
96%
77%
1,740
PRONGHORN FEDERAL 21-13TFH
99%
79%
3,255
Q4 Pronghorn Average
81%
65%
2,184
Production over a 24-hour period measured using a 40/64-inch choke.
14
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
100,000 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)
90,000 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
15
Big Tex Prospect Pecos, Reeves and Ward Counties, Texas OBJECTIVE Bone Spring Wolfcamp ACREAGE Whiting has assembled 120,719 gross (89,962 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 $60 MM. Developing Bone Spring prospect. Evaluating horizontal Wolfcamp and vertical Wolfbone potential.
16
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 76,065 Net Acres
. . 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 Testing longer laterals (7500 ft, 960-acre spacing). Planned budget in 2012 is $50MM for 11 wells.
General trend of Colorado Mineral Belt
17
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
18
Postle Field - Net Production Forecasts (1) Postle Field 3P Unrisked Production Forecast 25
20
Production Rate Mboe/d
120 - 130 MMcf/d Current CO2 Injection
15
10
P1 + P2 (no possible)
Proved
5
0
Jun â&#x20AC;&#x17E;05
Dec. â&#x20AC;&#x17E;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 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, 2010 reserve report. After 2020, Postle field proved reserve production is expected to decline at 8% - 11% year over year.
19
North Ward Estes - Net Production Forecasts (1) North Ward Ested 3P Unrisked Production Forecast (3) 30 285 - 295 MMcf/d Current CO2 Injection
Production Rate Mboe/d
25
20
P1 + P2 + P3 15
P1 + P2
10
Proved 5
0
Jun â&#x20AC;&#x17E;05
Dec. â&#x20AC;&#x17E;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 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, 2010 reserve report. After 2020, North Ward Estes field proved reserve production is expected to decline at 5% - 7% year over year.
20
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 â&#x20AC;&#x201C; 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."
21
Consistently Strong Margins Consistently Delivering Strong EBITDA Margins (1) $80.61/Bbl $5.02/Mcf
Whiting Realized Prices(1) $/BOE
$71.80/BOE
$69.06
$80.00
$61.48
$70.00
$53.57
$50.52
$60.00
$45.01
$44.70 $50.00
$45.10/65%
$49.54/69% $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%
3% 5% 7%
27%
20%
5% 5% 7%
2% 5% 7%
26%
18%
2% 5% 7% 17%
$0.00
2005
2006
Lease Operating Expense
2007
2008
Production Taxes
(1) Includes hedging adjustments.
2009 G&A
2010
Q3 11
Exploration Expense
EBITDA
22
Steady Production Growth
Average Daily Production (MBOE/d)
12% CAGR Production Production2005 â&#x20AC;&#x201C; 2012E
78.6
33.00
2005
41.5
40.4
2006
2007
47.7
2008
64.7
67.9
2010
2011
55.40
2009
2012E
23
Total Capitalization ($ 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%
24
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 10/12/2011) under which $600 million was drawn as of 09/30/11. Interest rate is currently 2.25% (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)
25
In Summary Oil weighted portfolio, long-lived reserve base
Reserves 86% oil; 13.9 year R/P (1)
Multi-year inventory of development, exploitation and exploration projects to drive organic production growth
Grown production 315% from 17.0 MBOE/D at Nov. 2003 IPO to 70.7 MBOE/D in Q4 2011; Project 13 - 19% YoY production growth in 2012
Disciplined acquirer with strong record of accretive acquisitions
16 acquisitions in 2004 â&#x20AC;&#x201C; 2010; 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 28.9% as of September 30, 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.
26
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
Contracted Volume
Weighted Average NYMEX Price Collar Range
As a Percentage of
Hedge
Dec-11
Hedge
Period
(Bbls per Month)
(per Bbl)
Oil Production
Period
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)
2012 Q1 Q2 Q3 Q4
Contracted Volume (MMBtu per Month)
33,381 32,477 31,502 30,640
Weighted Average NYMEX Price Collar Range
As a Percentage of
(per MMBtu)
Gas Production
$7.00 - $15.55 $6.00 - $13.60 $6.00 - $14.45 $7.00 – $13.40
1.60% 1.60% 1.50% 1.50%
Dec-11
As of January 10, 2012.
27
Fixed-Price Marketing Contracts
Existing Natural Gas Marketing Contracts Weighted Average
As a Percentage of
Hedge
Contracted Volume
Contracted Price
December 2011
Period
(MMBtu per Month)
(per MMBtu)
Gas Production
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%
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%
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%
2012
2013
2014
28
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.
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Discretionary Cash Flow (1) Reconciliation of Net Cash Provided by Operating Activities to Discretionary Cash Flow (In Thousands) Three Months Ended September 30, 2011
2010
2011
2010
$275,536
$280,134
$863,754
$720,267
Exploration
9,440
6,146
36,406
25,861
Exploratory dry hole costs
(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
Net cash provided by operating activities
Changes in working capital Preferred stock dividends paid Discretionary cash flow
(1)
Nine Months Ended September 30,
(1)
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.
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Whiting Provides Answers to Recent Investor and Analyst Questions (1)(2) Bakken and Three Forks Reservoir and Geology Q1 – What is the estimated oil in place per 1,280-acre spacing unit for the Middle Bakken? A1 – It varies across our fields and is difficult to calculate in this complex reservoir. We estimate that there are approximately 16-23 MMBOE per 1,280-acre unit. Q2 – What is the ultimate recovery for the Middle Bakken? A2 – We estimate the expected recovery to be between 8% and 12% of the original oil in place (OOIP). Note that we are drilling 2 – 4 wells on each 1,280-acre (2 sections) unit. Q3 – What is the estimated oil in place per 1,280-acre spacing unit for Three Forks / Pronghorn sands? A3 – It varies across our fields and is difficult to calculate in this complex reservoir . We estimate there to be 12 to 16 MMBOE per 1,280-acre spacing unit. Q4 – What is the ultimate recovery for Three Forks / Pronghorn sands? A4 – We estimate the expected recovery to be between 7% and 10% of OOIP. Again, we plan to drill at least 2-3 wells per 1,280-acre (2 sections) unit.
Q5 – How does the geology compare across your project areas in terms of porosity, thickness, and pressure gradients? Sanish, Lewis & Clark / Pronghorn, McKenzie/Williams Counties. A5 – In each project area it varies to some extent where the Middle Bakken exists over Sanish but pinches out and is almost non-existent over at Parshall. Permeability varies both in the matrix and due to the intensity of natural fracturing. Comparing prospect area to prospect area, there are wide variations in the geology. For example, the Middle Bakken has pinched out and does not exist at Lewis & Clark / Pronghorn. Q6 – Are the Scallion Limestone and Lodgepole formations valid resource targets? A6 – Yes, in various parts of the basin. (1)
The answers above include forward-looking statements that the Company believes to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Please refer to the beginning of this presentation for disclosures regarding "Forward-Looking Statements". (2) Please refer to the beginning of this presentation for disclosures regarding "Reserve and Resource Information." All volumes shown are unrisked.
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(Continued) Whiting Provides Answers to Recent Investor and Analyst Questions (1) Bakken Well Design and Completion Q7 – Why sliding sleeve versus perf and plug? A7 – It is mechanically simpler, less moving parts. We can complete wells through the winter. On a sliding sleeve job, we can pump continuously and complete the fracture stimulation in about 24 hours. Q8 – Where should the horizontal well be landed within the Middle Bakken target zone to achieve the best production?
A8 – It is our opinion that it is in the “B” zone of the Middle Bakken at Sanish and the “C” zone at Hidden Bench, Tarpon, Cassandra and Missouri Breaks. Q9 – Do the natural fractures impact fracture initiation? A9 – Probably, we see slightly lower fracturing pressure on the east side of Sanish field where we know the natural fracturing intensity is higher. Q10 – How might your completions vary by area and what are the geologic factors that drive your approach? A10 – If the rock is tighter and contains fewer natural fractures, we will pump more stages. Q11 – Why white sand vs. ceramics in the Sanish field? A11 – Our engineering evaluation indicates that we do not need ceramics to maintain open fractures in Sanish. Q12 – A few industry studies suggest that using ceramic proppants can increase EUR. Have you tested this and what are your thoughts on this matter? A12 – Ceramic proppant is about 5 times the cost of sand and it comes down to a cost/benefit evaluation. Our evaluations indicate that sand is providing very good results, but we continue to evaluate the available data.
(1)
The answers above include forward-looking statements that the Company believes to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Please refer to the beginning of this presentation for disclosures regarding "Forward-Looking Statements".
32
(Continued) Whiting Provides Answers to Recent Investor and Analyst Questions (1) Bakken and Other Development Planning and Well Costs
Q13 – To what do you attribute your lower completed well costs? Whiting appears to be in the range of $6 million to $8 million for the majority of its Bakken wells in the Williston Basin. Other Bakken operators have said they are in the $10 million to $12 million range? A13 – The largest cost savings come from our completion method. Instead of the “plug and perf” method, we use mostly sliding sleeve technology, which is more efficient and faster. Using sliding sleeves, we can save anywhere from $1 million to $3 million per fracture stimulation, depending on the number of frac stages. We also use white sand for proppant for our frac jobs instead of ceramics, which are about five times the cost. Second, our drilling time from spud to total depth is arguably the fastest in the Williston Basin. For instance, our average time at Sanish field is approximately 17 days when most other operators are in the 25 to 30 day range. This can save us anywhere from $800,000 to $1.3 million per well. Third, we are one of the most active operators in the Basin. The service companies and crews prefer a large number of completion opportunities in the same general area, which provides economies of scale and potential cost savings.
Q14 – What are your current spud to total depth and spud to spud times? How much more efficiency is possible? A14 – Across our program, spud to TD averages approximately 22 days. Spud to spud averages approximately 40 days. Our average of spud to TD for Sanish is approximately 17 days. Obviously there is more efficiency to be gained on non-Sanish wells. At Sanish we still think there are 2-3 days to be taken out of the process.
(1)
The answers above include forward-looking statements that the Company believes to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Please refer to the beginning of this presentation for disclosures regarding "Forward-Looking Statements".
33
(Continued) Whiting Provides Answers to Recent Investor and Analyst Questions (1) Bakken Development Planning and Well Costs (Continued) Q15 – How long does it take to complete a well? A15 – We have our wells completed within about three weeks of rig release with slightly longer times during severe winter conditions. Throughout the year this equates to completing 2-3 wells per week per frac crew. We build the battery during that time period. Consequently, once the well is frac‟d we can go down the sales line with the production. Q16 – With your expertise in EOR, is the Middle Bakken prospective for CO 2 flooding and when might you consider testing that, if so? A16 – We have evaluated this option. The initial issue is CO2. There is not a source with sufficient capacity in the Williston Basin. However, man made CO2 projects are being designed and may be available in 2-4 years. Natural fractures may make the CO2 move through the reservoir so fast that it makes a CO 2 project risky. In summary, it is unlikely.
Q17 – What type of primary/secondary recovery could be expected? A17 – Primary recovery 8% - 12%, secondary recovery currently questionable. Q18 – Could you review how you measure 24-hour and 30-day IP rates? A18 – After the frac job, we let the well sit for approximately 3 days to allow the gel to break down and the sand to keep the fractures open. We bring the well back at a fairly aggressive rate to ensure we get the balls off seat and get the entire horizontal lateral producing. After about 48 hours of flow back, we initiate the IP test and put the well on a 40/64ths choke and monitor the production for a 24-hour period. Production is measured by strapping the production tanks that are on location. We measure and internally report our production for every well we operate on a daily basis (company wide). The 30-day rate is just that, what the well averages over the first 30 days of production, excluding downtime.
(1)
The answers above include forward-looking statements that the Company believes to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Please refer to the beginning of this presentation for disclosures regarding "Forward-Looking Statements".
34
(Continued) Whiting Provides Answers to Recent Investor and Analyst Questions (1)
Bakken Well Productivity Q19 – How strong of an indicator is the 30-day rate on EUR? A19 – The 30-day average rate is an early indicator but additional production history is much more important. Average producing rates over 60 and 90 days and especially over the first six months are much more indicative. Q20 – What are the important milestones when attempting to measure a well‟s potential deliverability (30-day rates, well performance when on pump)? A20 – All of the above are indicators but 60 day, 90 day and six months average rates are perhaps better for early on scoping as these data start to define the hyperbolic curve the well may follow. Tubing pressure is also a good indicator.
Q21 – For your new project areas in the Western Williston Basin (Lewis & Clark, Pronghorn, Hidden Bench, Cassandra, Tarpon) where do you estimate the EURs fall in the 350-600 MBOE range?
A21 – Per the slides that illustrate the de-risked areas for each prospect, based on the preponderance of 30-day average rates, we believe Hidden Bench and Tarpon wells will be at or above the high end of the range, Pronghorn and Cassandra wells will be in the middle of the range, and the majority of Lewis & Clark wells will be toward the middle to low end of the range.
(1)
The answers above include forward-looking statements that the Company believes to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Please refer to the beginning of this presentation for disclosures regarding "Forward-Looking Statements".
35
(Continued) Whiting Provides Answers to Recent Investor and Analyst Questions (1)
Portfolio/EOR Q22 – In the 2011 year-end reserve report, what assumptions were made for North Ward Estes recovery (Proved, 2P and 3P)? A22 – Estimated remaining reserves at North Ward Estes are based on section by section geologic and reservoir engineering analysis and vary throughout the field depending on reservoir quality and our development plans. In general, the resulting EUR‟s indicate tertiary recoveries of 5-6% in the Proved category, up to 7-8% in the Probable category and up to 15% in the Possible category. Q23 – In terms of portfolio management, what are the key drivers behind your capital allocation process? The returns in the Bakken are different than EOR, but EOR is a bit more resilient through the cycles. A23 – You are correct. Generally, drilling provides higher IRR‟s and EOR projects have a greater assurance of reserve additions. We are fortunate to have a mixture of both in Whiting‟s inventory of projects. Drilling projects begin to decline after drilling activity peaks. EOR projects begin to incline about a year after project installation and commencement of H2O and CO2 injection. After production peaks on an EOR project production can plateau and remain relatively flat for several years before beginning to decline. This is caused by the pressure maintenance of the H2O and CO2. This plateau production may provide cash flow for many years to fund additional exploration and development drilling projects for the company.
(1)
The answers above include forward-looking statements that the Company believes to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Please refer to the beginning of this presentation for disclosures regarding "Reserve and Resource Information."
36