Whiting Petroleum Corporation Current Corporate Presentation June 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, 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, 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
Q1 2013 Production
89.1 MBOE/d
Proved Reserves(1)
378.8 MMBOE
% Oil
80%
R/P ratio(2)
13 years
Drilling on the Hidden Bench Prospect in McKenzie County, North Dakota.
(1) Whiting reserves at December 31, 2012 based on independent engineering. (2) R/P ratio based on year-end 2012 proved reserves and 2012 production.
3
Map of Operations
Q1 2013 Net Production 89.1 MBOE/d
ROCKY MOUNTAINS 66.1 MBOE/D MICHIGAN 2.6 MBOE/D
9%
3% 1%
13% MID-CONTINENT 7.9 MBOE/D
PERMIAN 11.3 MBOE/D
74%
GULF COAST 1.2 MBOE/D
Rockies
Permian
Mid-Con
Michigan
Gulf Coast 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 $5,407.0 million. We believe pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our pre-tax PV10% as a basis for comparison of the relative size and value of our proved reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our oil and gas properties and acquisitions. However, pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows. Our pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our proved oil and natural gas reserves.
(3)
Pre-tax PV10% of probable or possible reserves represent the present value of estimated future revenues to be generated from the production of probable or possible reserves, calculated net of estimated lease operating expenses, production taxes and future development costs, using costs as of the date of estimation without future escalation and using 12-month average prices, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or future income taxes and discounted using an annual discount rate of 10%. With respect to pre-tax PV10% amounts for probable or possible reserves, there do not exist any directly comparable US GAAP measures, and such amounts do not purport to present the fair value of our probable and possible reserves.
6
Capital Budget for Key Development Areas in 2013 ($ in millions)
Facilities 178 MM
Well Work, Misc. Costs, Other 150 MM
Exploration Expense (2) 82 MM Land 108 MM Non-Operated 164 MM
Central Rockies 136 MM EOR 240 MM
(1)These
Northern Rockies 1,142 MM
Northern Rockies EOR Central Rockies Non-Operated Land Exploration Expense (2) Facilities Well Work, Misc. Costs, Other Total Budget
EST. 2013 CAPEX IN MM $1,142 240 136 164 108 82 178 150 $2,200
% 52% 11% 6% 7% 5% 4% 8% 7% 100%
Gross Wells 219 NA(1) 37
Net Wells 148 NA(1) 27
256
175
multi-year CO2 projects involve many re-entries, workovers and conversions. Therefore, they are budgeted on a project basis not a well basis. of exploration salaries, seismic activities, delay rentals and exploratory drilling.
(2)Comprised
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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
8
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
9
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 (MMBOE) 4 wells 10% Recovery (Current Design)
7 wells 15% Recovery
7 wells 20% Recovery
0.75
0.64
0.85
* Assumes fieldwide average with constant GOR (1000 MCF/BO) ** Bakken Shale recovery efficiency is generally considered < 2% 10
Williston Basin Primary and Prospective Drilling Plan by Area
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Whiting Lease Areas in Williston Basin
Sanish
Field
Target
Gross Acres
Net Acres
Sanish / Parshall
Middle Bakken / Three Forks
174,466
82,400
Pronghorn
Pronghorn Sand
196,822
128,080
Lewis & Clark
Three Forks
199,660
134,114
Hidden Bench
Middle Bakken / Three Forks
47,958
28,832
CASSANDRA
STARBUCK
SANISH & PARSHALL TARPON
8,805
6,258
Starbuck
Middle Bakken / Three Forks Middle Bakken / Three Forks / Red River
105,664
91,228
Missouri Breaks
Middle Bakken / Three Forks
95,803
65,481
Cassandra
Middle Bakken / Three Forks
30,347
13,883
Big Island
Red River
176,900
125,530
75,377
28,719
1,111,802
704,525
Tarpon
MISSOURI BREAKS
HIDDEN BENCH
LEWIS & CLARK
Other ND & Montana
BIG ISLAND
(1)
Pronghorn (1)
As of 3/31/13, Whitingâ&#x20AC;&#x2122;s total acreage cost in 704,525 net acres is approximately $371 million, or $526 per net acre.
12
Southern Williston Basin Lewis & Clark and Pronghorn (March 31, 2013) Planned Higher Density Pilot Locations
OBJECTIVE Pronghorn Sand 3 wells per 1,280-acre spacing unit
ACREAGE Whiting has assembled 396,482 gross (262,194 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
13
Western Williston Basin Cassandra, Hidden Bench, Tarpon, and Missouri Breaks (March 31, 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 182,913 gross (114,454 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
HIDDEN BENCH
Identified an additional reservoir (the “Middle Bakken Silt”) positioned between the Middle Bakken and Three Forks. Plan to test this zone by drilling 160 acre spaced wells above and below this target zone and stimulating these wells with large frac volumes. We believe that this higher density drilling could also improve our recovery efficiency in the Middle Bakken reservoir. (1)
Tarpon primary development on 3 Middle BKN; 2 Upper TKS due to high natural fracturing. Excludes Upper TFK at Missouri Breaks.
14
Sanish Area Sanish and Parshall Fields (March 31, 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 174,466 gross (82,400 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 Plan a higher density pilot program in the Sanish field in the first half of 2013 that 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.
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Red River Plays Sheridan, Roosevelt, Golden Valley and Wibaux Counties OBJECTIVE Vertical Red River
BIG ISLAND Whiting has assembled 176,900 gross (125,530 net) acres in our Big Island development project: • 11 of 12 successful completions to date. • 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 105,664 gross (91,228 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 95,803 gross (65,481 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 Stecker 32-9 producing 308 BOEPD and the Davidson 13-19 producing 226 BOEPD.
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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 17 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.
Productivity Increase with Shift to New Development Areas
2012 Average 30, 60, 90 Day Rates (BOPD) Sanish Bakken and Three Forks vs. Pronghorn, Lewis & Clark and Hidden Bench 700
600
655
555 524
500
472 428
419 400
300
200
100
30 Day
60 Day Sanish Bakken and Three Forks
90 Day
Pronghorn, Lewis & Clark and Hidden Bench
18
NDPA Williston Basin Oil Production & Export Capacity
(1)
BOPD
Feb 2013 Production 837,906 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
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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 (4/15/13)
69 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
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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 (4/15/13)
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
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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 (MMBOE)
C
16 wells 10% Recovery 0.37
16 wells 15% Recovery 0.55
16 wells 20% Recovery 0.74
* GOR=500 cf/bo ** Stimulated Rock Volume 22
Redtail Niobrara Prospect Weld County, Colorado (March 31, 2013) OBJECTIVE Niobrara “B” Shale Niobrara “A” Shale Whiting Wells Whiting Lease Area
DEVELOPMENT PLAN Mix of 960 and 640-acre spacing units 8 Wells per spacing unit Niobrara “B” 4 Wells per spacing unit Niobrara “A” ACREAGE Whiting has assembled 120,354 gross (87,610 net) acres in our Redtail prospect in the northeastern portion of the DJ Basin. • Average WI of 72% • Average NRI of 57% Whiting’s acreage lies along the Colorado Mineral Belt. This geological trend brackets the most productive acreage in the Niobrara formation. COMPLETED WELL COST Horizontal: $4 MM to $5.5 MM Razor 26-3524H IP: 861 BOE/D
General trend of Colorado Mineral Belt
DRILLING HIGHLIGHTS Recently completed the Razor 26-3524H flowing 861 BOEPD from the Niobrara “B” formation. Currently have one rig drilling and plan to add a second rig midyear and a third rig before year-end.
23
Big Tex Prospect Pecos, Reeves, and Ward Counties, Texas (March 31, 2013)
OBJECTIVE Vertical Wolfbone Hz. Wolfcamp ACREAGE Whiting has assembled 93,207 gross (69,163 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 Horizontal: $7 MM - $8 MM 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
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 3 Upper Wolfcamp wells in 2013.
Stewart 101 IP: 232 BOE/D
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EOR Projects Postle and North Ward Estes Fields Whiting
Postle N. Ward Estes
Total Whiting
% Postle N. Ward Estes
301.3 40.1 224.3 378.8
40% 52% 11% 39% (2)
12/31/12 Proved Reserves(1) Oil – MMBbl NGL - MMNgl Gas – Bcf Total – MMBOE % Crude Oil
180.1 19.3 199.1 232.6
121.2 20.8 25.2 146.2(2)(3)
77%
83%
80%
72.9
16.2
89.1
Q1 2013 Production Total – MBOE/d
18%
(1)
Based on independent engineering by Cawley, Gillespie & Associates, Inc. at December 31, 2012. Includes Ancillary Properties (3) Since their acquisition in late 2004 and early 2005, through December 31, 2012 Postle and North Ward Estes has produced 39.0 MMBOE net to Whiting. (2)
MID-CONTINENT McElmo Dome
Headquarters
Bravo Dome
Field Office Whiting Properties
PERMIAN
DENVER CITY
North Ward Estes & Ancillary Fields Postle Field CO2 Pipeline
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)
60,377 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 $88.11/Bbl NGL $42.56/BOE Gas $3.80/Mcf
$69.06
$80.00
Whiting Realized Prices(1) $/BOE
$73.88 $61.48
$70.00 $60.00
$74.77/BOE
$69.85
$53.57 $45.01
$50.00
$50.65/68%
$45.10/65%
$49.19/66%
$49.98/67%
$41.58/68%
$40.00 $30.00
$20.00 $10.00
$31.29/58% 3% 5% 7%
27%
$25.71/57% 3% 5% 7%
20%
2%
3%
2%
5% 5% 7%
2% 5% 7%
5% 8%
6% 8%
8%
26%
18%
17%
18%
17%
5%
$0.00
2007
2008
Lease Operating Expense
2009
2010
Production Taxes
(1) Includes hedging adjustments.
2011 G&A
2012
Q1 2013
Exploration Expense
EBITDA
27
Whiting Highlights
OIL WEIGHTED, LONGLIVED RESERVE BASE
MULTI-YEAR INVENTORY TO DRIVE ORGANIC PRODUCTION GROWTH
•9,661 GROSS (4,503.2 NET) POTENTIAL DRILLING LOCATIONS •PROJECT +12% TO +16% YOY PRODUCTION GROWTH IN 2013
DISCIPLINED ACQUIRER WITH STRONG RECORD OF ACCRETIVE ACQUISITIONS
•16 ACQUISITIONS 2004-2012 •230.9 MMBOE AT $8.23 PER BOE ACQ COST •ACQUIRED 704,525 NET ACRES IN THE WILLISTON BASIN 2005-2012; $526 PER NET ACRE AVERAGE
COMMITMENT TO FINANCIAL STRENGTH
•TOTAL DEBT TO CAP OF 37.3% AS OF MAR-31-13
PROVEN MANAGEMENT AND TECHNICAL TEAM
(1)
•RESERVES: 80% OIL (1) •13 YEAR R/P(1)
•AVERAGE 29 YEARS EXPERIENCE
Percent oil reserves and R/P ratio based on year-end 2012 proved reserves and total 2012 production.
28