Whiting Petroleum Corporation Announces Fourth Quarter and Full-Year 2012 Financial and Operating Results

Wed Feb 27, 2013 4:00pm EST

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Record Production of 30.21 MMBOE (82,540 BOE/d) in 2012 Up 22% Over 24.78 MMBOE
(67,890 BOE/d) in 2011

Proved Reserves Increase 10% to a Record 378.8 MMBOE; Adding Back 10.6 MMBOE
Conveyed to Trust - Proved Reserves Up 13%; Company Achieves 246% Reserve
Replacement

Q4 2012 Net Income Available to Common Shareholders of $81.4 Million or $0.69
per Diluted Share and Adjusted Net Income of $97.9 Million or $0.83 per Diluted
Share

Q4 2012 Discretionary Cash Flow Totals a Record $381.7 Million

2013 Capital Budget of $2.2 Billion; Year-Over-Year Production Growth Guidance
of +12% to +16%

Tarpon Prospect Well in North Dakota Tests 6,879 BOE/d
DENVER--(Business Wire)--
Whiting Petroleum Corporation`s (NYSE: WLL) production in the fourth quarter of
2012 totaled 7.917 million barrels of oil equivalent (MMBOE), of which 86% were
crude oil/natural gas liquids (NGLs). This fourth quarter 2012 production total
equates to a daily average production rate of 86,055 barrels of oil equivalent
(BOE), representing a 22% increase over the fourth quarter 2011 average daily
rate of 70,685 BOE per day and a 4% increase over the third quarter 2012 average
daily rate of 82,615 BOE per day. 

Production in 2012 totaled a record 30.21 MMBOE or 82,540 BOE per day. This
represents a 22% increase over total production of 24.78 MMBOE or 67,890 BOE per
day in 2011. Adding back the 4,500 BOE per day of production that was conveyed
to Whiting USA Trust II in March 2012, our production in 2012 was up 28% over
2011. 

James J. Volker, Whiting`s Chairman and CEO, commented, "2012 was a record year
for Whiting Petroleum, and we are off to a great start in 2013.The development
of the fields we discovered in 2011 such as Pronghorn, Hidden Bench, Tarpon and
Redtail generated excellent results in 2012.In the wake of this development, we
posted records in production, proved reserves and discretionary cash
flow.According to the December 2012 Oil and Gas Production Report published by
the North Dakota State Industrial Commission, Department of Minerals, Oil and
Gas Division, Whiting was the number one oil producer in North Dakota at
66,155.7 barrels per day."

Mr. Volker continued, "For the foreseeable future, our objective is to generate
double-digit production growth while spending close to our discretionary cash
flow.Our 2013 capital budget of $2.2 billion is expected to yield year-over-year
production growth in the 12% to 16% range."

We believe the following factors will lead to a strong year in 2013 for Whiting
and our shareholders:

●Optimization programs that should lead to efficient, low-cost drilling and
completion operations;

●Higher density pilot projects at Sanish, Pronghorn and Hidden Bench;

●Solid cash flow and balance sheet;

●Strong Bakken oil prices as differentials improve;

●The emergence of our Redtail prospect as a major resource play.

Operating and Financial Results

The following table summarizes the fourth quarter operating and financial
results for 2012 and 2011:

                                                                                                   
 Three Months Ended December 31,                                                                   
                                                                 2012       2011       Change      
 Production (MBOE/d)                                             86.06      70.69      22    %     
 Discretionary Cash Flow-MM$ (1)                                 381.7      328.8      16    %     
 Realized Price ($/BOE)                                          71.09      75.07      (5    ) %   
 Total Revenues-MM$                                              577.1      498.6      16    %     
 Net Income Available to Common Shareholders-MM$                 81.4       62.6       30    %     
 Per Basic Share                                                 $0.69      $0.54      28    %     
 Per Diluted Share                                               $0.69      $0.53      30    %     
 Adjusted Net Income Available to Common Shareholders-MM$ (2)    97.9       124.5      (21   ) %   
 Per Basic Share                                                 $0.83      $1.06      (22   ) %   
 Per Diluted Share                                               $0.83      $1.05      (21   ) %   
                                                                                                   
                                                                                                   
 Twelve Months Ended December 31,                                                                  
                                                                 2012       2011       Change      
 Production (MBOE/d)                                             82.54      67.89      22    %     
 Discretionary Cash Flow-MM$ (1)                                 1,387.5    1,242.7    12    %     
 Realized Price ($/BOE)                                          69.85      73.88      (5    ) %   
 Total Revenues-MM$                                              2,173.5    1,899.6    14    %     
 Net Income Available to Common Shareholders-MM$                 413.1      490.6      (16   ) %   
 Per Basic Share                                                 $3.51      $4.18      (16   ) %   
 Per Diluted Share                                               $3.48      $4.14      (16   ) %   
 Adjusted Net Income Available to Common Shareholders-MM$ (2)    393.5      456.2      (14   ) %   
 Per Basic Share                                                 $3.35      $3.89      (14   ) %   
 Per Diluted Share                                               $3.31      $3.85      (14   ) %   
                                                                                                   


 (1)    A reconciliation of discretionary cash flow to net cash provided by operating activities is included later in this news release.                                 
 (2)    A reconciliation of adjusted net income available to common shareholders to net income available to common shareholders is included later in this news release.  
                                                                                                                                                                         


Proved Reserves at December 31, 2012

As of December 31, 2012, Whiting had estimated proved reserves of 378.8 MMBOE,
of which 64% were classified as proved developed. These estimated proved
reserves had a pre-tax PV10% value of $7,283.9 million, of which approximately
99% came from properties located in Whiting`s Rocky Mountain, Permian Basin and
Mid-Continent core areas. 

The following is a summary of Whiting`s changes in quantities of proved oil and
gas reserves for the year ended December 31, 2012:

                                                                                                     
                                    Oil              NGLs            Natural          Total          
                                    (MBbl)           
(MBbl)         
Gas             (MBOE)         
                                                                     
(MMcf)                         
 Balance - December 31, 2011        260,144          37,609          284,975          345,249        
 Extensions and discoveries         68,134           6,526           40,915           81,479         
 Sales of minerals in place         (7,960   )       (320    )       (13,987  )       (10,611  )     
 Production                         (23,139  )       (2,766  )       (25,827  )       (30,209  )     
 Revisions to previous estimates    4,106            (951    )       (61,812  )       (7,148   )     
 Balance - December 31, 2012        301,285          40,098          224,264          378,760        
                                                                                                     


Whiting`s proved reserves of 378.8 MMBOE represented a 10% increase over the
345.2 MMBOE of proved reserves at year-end 2011, which equates to 246% reserve
replacement (81,479 MBOE extensions and discoveries less 7,148 MBOE revisions
equals 74,331 MBOE in net reserves added; 74,331 MBOE divided by 30,209 MBOE
production = 246% reserve replacement). Adding back the 10.6 MMBOE that was
conveyed to Whiting USA Trust II, our proved reserves were up 13%. An estimated
81.5 MMBOE of proved reserves were added through exploration and development
activities. This represents a 68% increase over the 48.6 MMBOE of proved
reserves that were added from exploration and development in 2011. 

Most of the proved reserve additions during 2012 came from the Company`s Bakken
and Three Forks development in the Williston Basin of North Dakota and Montana.
Whiting booked an estimated 66.4 MMBOE of new Bakken and Three Forks proved
reserves, bringing its total proved reserves in the Northern Rockies to 165.1
MMBOE at year-end 2012. Of this 165.1 MMBOE, 67% were proved developed and 33%
were proved undeveloped. 

Probable and Possible Reserves at December 31, 2012

At year-end 2012, Whiting`s probable reserves were estimated to be 115.2 MMBOE
and our possible reserves were estimated to be 171.2 MMBOE, for a total of 286.3
MMBOE. The year-end 2012 estimated pre-tax PV10% for our probable and possible
reserves was $2,621.4 million. 

As with our proved reserves, 100% of Whiting`s probable and possible reserve
estimates were independently engineered by Cawley, Gillespie & Associates, Inc.
Please refer to "Disclosure Regarding Reserves and Resources" later in this news
release for information on probable and possible reserves. 

The following table summarizes our proved, probable and possible reserves:

                                                                                    
 3P Reserves (1)                                                                    
                                                                                    
                                                                Pre-Tax             
                                   Natural                      PV10%               
             Oil        NGLS       Gas        Total      %      Value        % of   
             (MMBbl)    (MMBbl)    (Bcf)      (MMBOE)    Oil    (In MM)      Total  
                                                                                    
 Proved      301.3      40.1       224.3      378.8      80%    $7,284(2)    73%    
 Probable    85.0       11.9       109.6      115.2      74%    $1,262(3)    13%    
 Possible    123.2      21.9       156.4      171.2      72%    $1,359(3)    14%    
                                                                                    


 (1)    Oil and gas reserve quantities and related discounted future net cash flows have been derived from oil and gas prices calculated using an average of the first-day-of-the 
        month NYMEX price for each month within the 12 months ended December 31, 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.                                                                                                                                                                 
                                                                                                                                                                                  


Potential Future Drilling Locations

Based on independent engineering and internal estimates, Whiting projects it has
a total of 9,661 gross (4,503.2 net) potential future drilling locations. These
consist of 7,556 gross (3,623.3 net) primary locations identified in our reserve
database and 2,105 gross (879.9 net) prospective locations supported by
successful exploration drilling or extensive geoscience. Of these gross
locations, 50% are located in our Williston Basin Bakken/Three Forks plays and
25% are located in our Redtail Niobrara play. 

The following table summarizes our potential gross and net drilling locations by
core area:

                                                                                                                                    
 Identified Primary Locations                                                                                                       
 Northern Rockies                                                           Gross    Net        Wells per Spacing Unit              
 Southern Williston (Lewis & Clark; Pronghorn)                                     1,104    410.2      3 Pronghorn Sand / 1280             
 Western Williston(1) (Cassandra; Hidden Bench; Tarpon; Missouri Breaks)    1,174    380.5      4 Middle BKN; 3 Upper TFK / 1280    
 Sanish (Sanish; Parshall) (2)                                              260      118.1      3.5 Middle BKN; 3 Upper TFK / 1280  
 Other (3)                                                                  588      340.3                                          
                                                                                                                                    
 Total                                                                      3,126    1,249.1                                        
 Central Rockies                                                                                                                    
 Redtail Niobrara                                                           2,420    1,215.7    8 Nio "B"; 4 Nio "A" / 640 - 960    
 Other (4)                                                                  958      654.1                                          
                                                                                                                                    
 Total                                                                      3,378    1,869.8                                        
 Gulf Coast                                                                 131      98.1                                           
 Mid-Cont                                                                   41       33.7                                           
 Permian Basin (5)                                                          817      319.3                                          
 Michigan                                                                   63       53.3                                           
                                                                                                                                    
 Total Primary Inventory                                                    7,556    3,623.3                                        
                                                                                                                                    
 Identified Prospective Locations                                                                                                   
 Williston Basin                                                                                                                    
 Williston Basin New Objectives                                             Gross    Net        Wells per Spacing Unit              
 Missouri Breaks Upper Three Forks                                          321      102.8      3 Upper TFK / 1280                  
 Hidden Bench Lower Bakken Silt / Higher Density Pilot                      556      161.9      4 BKN Silt; 4 Middle BKN per 1280   
 Cassandra Lower Three Forks                                                120      40.0       4 Lower TFK per 1280                
 Tarpon Lower Three Forks                                                   40       15.0       3 Lower TFK per 1280                
 Total                                                                      1,037    319.7                                          
 Williston Basin Higher Density Locations                                                                                           
 Pronghorn Sand Higher Density                                              453      167.3      3 Add'l Pronghorn Sand / 1280       
 Sanish Higher Density and Infill                                           191      175.9      3 Add'l Middle BKN / 1280           
 Total                                                                      644      343.2                                          
 Williston Basin Total Prospective Locations                                1,681    662.9                                          
 Permian Basin                                                                                                                      
 Big Tex Horizontal                                                         424      217.0      6 Upper Wolfcamp / 640              
 Total Prospective Inventory                                                2,105    879.9                                          
                                                                                                                                    
 Total Potential Locations (6)                                              9,661    4,503.2                                        
                                                                                                                                    


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


2012 Capital Expenditures

Whiting`s capital expenditures totaled $2,112 million in 2012 or approximately
$212 million above its $1,900 million capital budget. The increase was due to a
higher level of both operated and non-operated drilling activity. In total, we
completed 192.9 net wells versus a projected 160 net wells. 

2013 Capital Budget

Our 2013 capital budget is $2,200 million, which we expect to fund substantially
with net cash provided by our operating activities, borrowings under our credit
facility and certain oil and gas property divestitures. Whiting expects to
invest $1,914 million of the 2013 capital budget in exploration and development
activity, $108 million for land, and $178 million for facilities. Based on this
level of capital spending, we forecast production of 33.8 MMBOE - 35.0 MMBOE for
2013, an increase of 12% - 16% over our 2012 production of 30.2 MMBOE. 

Our 2013 capital budget is currently allocated among our major development areas
as indicated in the table below:

                                                                   
                           2013                                    
                           CAPEX     Gross    Net                  
                           (MM)      Wells    Wells    % of Total  
 Northern Rockies          $1,142    219      148      52%         
 EOR                       240       NA(2)    NA(2)    11%         
 Central Rockies           136       37       27       6%          
 Non-Operated              164                         7%          
 Land                      108                         5%          
 Exploration (1)           82                          4%          
 Facilities                178                         8%          
 Well Work, Misc. Costs    150                         7%          
 Total Budget              $2,200    256      175      100%        
                                                                   


 (1)    Comprised primarily of exploration salaries, seismic activities, delay rentals and exploratory drilling.                                             
 (2)    These multi-year CO2 projects involve many re-entries, workovers and conversions. Therefore, they are budgeted on a project basis not a well basis.  


Operations Update

Core Development Areas

Bakken and Three Forks Development

In 2012, we experienced significant productivity increases as we moved into
development drilling mode in new fields in the Southern and Western Williston
Basin. As the following table illustrates, our average well drilled in the
Bakken / Pronghorn / Three Forks hydrocarbon system posted higher 30, 60 and
90-day average rates year-over-year:

                                     
 Average Rate All Whiting            
 Bakken, Pronghorn, Three Forks Wells 
                                     
         30-Day    60-Day    90-Day  
         Rate      Rate      Rate    
 2012    572       470       403     
 2011    432       373       338     
                                     


Southern Williston Basin

The Southern Williston Basin encompasses our Pronghorn and Lewis & Clark
prospects, which encompass a total of 398,334 gross (262,974 net) acres. Fourth
quarter 2012 production from this region averaged 13,430 BOE per day. This daily
rate represents a 10% increase over the 12,190 BOE per day rate in the third
quarter of 2012. 

Pronghorn Prospect. We experienced exceptional drilling results in the fourth
quarter at our Pronghorn prospect. As detailed in the following table,
significant fourth quarter 2012 completions include eight wells with 24-hour
initial production rates that exceeded 2,000 BOE per day:

                                                    
 Well Name              IP Date       WI%    BOE/d  
 3J TRUST 44-8PH        11/24/2012    89%    2,696  
 FROEHLICH 11-28PH      11/27/2012    89%    2,644  
 MARSH 34-18PH          12/09/2012    65%    2,340  
 FROEHLICH 21-28PH      11/28/2012    89%    2,301  
 OBRIGEWITCH 41-17PH    11/24/2012    96%    2,292  
 FROEHLICH 41-28PH      11/27/2012    89%    2,288  
 FRANK 14-7PH           11/14/2012    90%    2,165  
 OBRIGEWITCH 41-16PH    11/27/2012    89%    2,110  
 Average                              87%    2,355  
                                                    


We intend to conduct a higher density pilot program at Pronghorn. Our plan is to
drill six Pronghorn Sand wells per 1,280-acre spacing unit, which is up from our
initial plan of three wells per spacing unit. 

Western Williston Basin

The Western Williston Basin includes our Hidden Bench, Tarpon, Missouri Breaks
and Cassandra prospects. These areas represent a total of 183,508 gross (114,732
net) acres. Production from the Western Williston Basin averaged 5,120 BOE per
day in the fourth quarter of 2012, which represented a 47% increase over the
3,485 BOE per day average rate in the third quarter of 2012. 

Tarpon Prospect. We drilled another prolific well at our Tarpon prospect in
McKenzie County, North Dakota. The Tarpon Federal 21-4-3H was tested on December
28, 2012 flowing 4,971 barrels of oil and 11,450 Mcf of gas (6,879 BOE) per day
from the Middle Bakken formation. This is the third best well drilled to date in
the Williston Basin, the first being Whiting`s Tarpon Federal 21-4H with an
initial production rate of 7,009 BOE per day. We hold a 56% working interest and
a 45% net revenue interest in the Tarpon Federal 21-4-3H. We have implemented
pad drilling at Tarpon with plans to drill three wells off of each pad. 

Hidden Bench Prospect. Based on core analysis, we have identified an additional
reservoir positioned between the Middle Bakken and Three Forks that has
demonstrated high oil in place and may significantly increase reserves in this
area. We plan to test this zone which we refer to as the "Middle Bakken Silt" 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. 

Missouri Breaks Prospect. We hold 95,928 gross (66,095 net) acres in the
Missouri Breaks prospect, located in Richland County, Montana and McKenzie
County, North Dakota. We continue to de-risk our acreage in the Missouri Breaks
area. We have now drilled successful wells on the western, eastern and southern
portions of our acreage. On October 27, 2012, we completed the Amber Elizabeth
9-4H in the Middle Bakken formation flowing 1,315 BOE per day. This was our
first well drilled in the eastern portion of Missouri Breaks. 

Sanish Field

Whiting`s net production from the Sanish field averaged 32,590 BOE per day in
the fourth quarter of 2012, an increase of 4% over the third quarter 2012
average of 31,400 BOE per day. Net production from Sanish in 2012 totaled 11.4
MMBOE (an average of 31,081 BOE per day), representing a 40% increase over 2011.
Whiting continues to generate strong results from the field. Highlighting recent
results was the completion of the Fladeland 14-33H, which was completed in the
Middle Bakken formation flowing 3,220 BOE per day. This wing well`s 7,279-foot
lateral was fraced in a total of 22 stages. 

Also of note was the completion of the Lioneld Fladeland 12-12H, which was
completed in the Middle Bakken formation flowing 2,747 BOE per day on December
15, 2012. This well was drilled on the western edge of the Sanish field and was
fraced in 30 stages. 

We plan to initiate a higher density pilot program in the Sanish field in the
first half of 2013. If successful, this could add an additional three Middle
Bakken locations per 1,280-acre spacing unit. We also plan to refrac several
wells at Sanish in 2013. 

Red River Plays

Big Island. We currently hold 172,464 gross (122,389 net) acres in the Big
Island prospect, which is located in Golden Valley County, North Dakota and
Wibaux County, Montana. We have identified more than 50 vertical Red River
prospects at our Big Island play using 3-D seismic interpretation. We are
currently shooting 3-D seismic on the northwest portion of Big Island with the
intention of identifying additional prospect locations. Estimated ultimate
recoveries for these wells range from 200,000 BOE to 300,000 BOE. The wells have
an estimated completed well cost of $3.0 to $3.5 million. 

Our most recent completion at Big Island, the Katherine 33-23, flowed 593 BOE
per day from the Upper Red River "D" zone on December 17, 2012. Whiting holds a
99% working interest and a 79% net revenue interest in this vertical well. We
currently plan to test the Lower Red River "D" zone with a horizontal well in
mid-2013. 

Starbuck Prospect. We are currently conducting a 283-square-mile 3-D seismic
shoot at our Starbuck prospect in order to identify seismic anomalies in the
Upper Red River "D" zone. This shoot was approximately 60% complete at the end
of January 2013. We hold 104,508 gross (92,227 net) acres in the Starbuck
prospect, which is located in Roosevelt County, Montana. 

Midstream Assets

Robinson Lake Gas Plant. As of December 31, 2012, our gas plant at Robinson Lake
was processing 67 MMcf of gas per day (gross). We added compression in September
2012 that brought the plant`s inlet capacity to 72 MMcf per day, and we have the
ability to increase to 90 MMcf per day in the future. Whiting owns a 50%
interest in the plant. 

Belfield Gas Processing Plant. The Belfield plant was processing 18 MMcf of gas
per day (gross) as of December 31, 2012. Currently, there is inlet compression
in place to process 24 MMcf per day. Whiting owns 50% of the Belfield plant. We
began connecting other operators` wells to the plant in November 2012. 

Other Development Areas

Denver Basin: Redtail Niobrara Prospect. We hold a total of 109,856 gross
(79,467 net) acres in our Redtail prospect, located in the Denver Julesberg
Basin in Weld County, Colorado. Highlighting recent results from the Niobrara
"B" zone was the completion of the Wildhorse 02-0214H. This well flowed 534
barrels of oil and 757 Mcf of gas (660 BOE) per day on October 20, 2012. Whiting
holds a 100% working interest and an 80% net revenue interest in the Wildhorse
well, which was drilled on a 640-acre spacing unit. 

We plan to construct a new gas processing plant at our Redtail prospect.
Construction is expected to be completed in early 2014. The plant`s planned
inlet capacity is 15 MMcf of gas per day. We currently have one drilling rig
running at Redtail. We plan to add a second rig around mid-year and a third rig
once the plant is completed. 

Delaware Basin:Big Tex Prospect. Whiting`s lease position at Big Tex consists of
116,694 gross (86,882 net) acres, located primarily in Pecos County, Texas. On
January 23, 2013, we completed the May 2502H flowing 674 barrels of oil per day
from the Wolfcamp formation. The well`s peak 30-day average was 397 barrels of
oil per day. Whiting owns a 100% working interest and an 80% net revenue
interest in the May 2502H. 

The May 2502H well offsets the May 2501, a vertical Wolfcamp well that was
completed in May 2012 flowing 353 BOE per day from the Upper Wolfcamp formation.
Both May wells are located on the southwest side of the Big Tex prospect. 

EOR Projects

North Ward Estes Field. Net production from our North Ward Estes field averaged
8,540 BOE per day in the fourth quarter of 2012. One of the largest phases at
North Ward Estes (Phase 3B) is pressuring up with CO2, and we are beginning to
see a production response. Current production from the field is approximately
9,000 BOE per day. Whiting is currently injecting approximately 350 MMcf of CO2
per day into the field, of which about 63% is recycled gas. 

Optimization Programs

Over the past three and a half years, our use of the "Drill Well on Paper"
("DWOP") optimization process to perform step-by-step analysis of the drilling
programs in the Bakken and Three Forks formations in North Dakota has allowed us
to reduce average drill times from 38 days to 18.5 days per well in the Sanish
field and from 35 days to 17.0 days per well in other fields throughout North
Dakota. 

As post-DWOP drill times in North Dakota have stabilized at these reduced rates,
drilling procedures are being modified to utilize pad drilling technologies to
further reduce drilling time and costs per well. Pad drilling in a batch
drilling methodology is utilized to reduce surface disturbance, rig
mobilization, and service costs by drilling two or three wells from a single
drilling location. Drilling costs for pad wells have been over $175,000 lower in
the Sanish field and $502,000 lower in the Pronghorn field than single well
locations in the same fields. Whiting currently has nine pad capable rigs
drilling in North Dakota with one additional pad capable rig to start late in
the first quarter of 2013. 

In September of 2012, we initiated a program to reduce our overall cycle time,
or the time from spud to first production. This program initially covered
operations in our Pronghorn, Lewis & Clark, Hidden Bench, Tarpon and East
Missouri Breaks fields. The focus of the program is on: the construction of pads
and tank batteries; drilling rig mobilization times; pre-job preparation and
timing for fracture stimulations; and, post-frac flow back and timing of
production to facilities. 

To date, we have reduced this cycle time by 23.7 days, to 67.1 days from 90.8
days. The cycle time reduction is resulting in accelerated production and
drilling and completion cost savings. 

Operated Drilling Rig Count

As of February 1, 2013, 24 operated drilling rigs were active on our properties.
The breakdown of our operated rigs as of February 1, 2013 was as follows:

                             
 Region                      
                             
 Northern Rockies      20    
 Permian Basin         --    
 Central Rockies       2     
 EOR Projects:               
 Postle                1     
 North Ward Estes      1     
 Total                 24    
                             


Other Financial and Operating Results

The following table summarizes the Company`s net production and commodity price
realizations for the quarters ended December 31, 2012 and 2011:

                                                                                           
                                      Three Months                                         
                                      Ended December 31,                                   
 Production                           2012                  2011               Change      
 Oil (MMBbl)                               6.12                  4.91          25    %     
 NGLs (MMBbl)                              0.71                  0.54          32    %     
 Natural gas (Bcf)                         6.52                  6.35          3     %     
 Total equivalent (MMBOE)                  7.92                  6.50          22    %     
                                                                                           
 Average Sales Price                                                                       
 Oil (per Bbl):                                                                            
 Price received                       $    83.50            $    88.87         (6    %)    
 Effect of crude oil hedging (1)           (0.41  )              (0.85  )                  
 Realized price                       $    83.09            $    88.02         (6    %)    
 NYMEX oil (per Bbl)                  $    88.20            $    94.02         (6    %)    
                                                                                           
 NGLs (per Bbl):                                                                           
 Realized price                       $    43.10            $    48.46         (11   %)    
                                                                                           
 Natural gas (per Mcf):                                                                    
 Price received                       $    3.60             $    4.72          (24   %)    
 Effect of natural gas hedging (1)         0.05                  0.05                      
 Realized price                       $    3.65             $    4.77          (23   %)    
 NYMEX natural gas (per Mcf)          $    3.41             $    3.54          (4    %)    
                                                                                           


 (1)    Whiting realized pre-tax cash settlement losses of $2.5 million on its crude oil hedges and gains of $0.3 million on its natural gas hedges during the fourth quarter of 2012. A summary of Whiting`s outstanding hedges is included later in this news release.  
                                                                                                                                                                                                                                                                          


Fourth Quarter and Full-Year 2012 Costs and Margins

A summary of production, cash revenues and cash costs on a per BOE basis is as
follows:

                                                                                                                        
                                      Per BOE, Except Production                                                        
                                      Three Months                               Twelve Months                          
                                      Ended December 31,                         Ended December 31,                     
                                      2012                  2011                 2012                  2011             
 Production (MMBOE)                        7.92                  6.50                 30.21                 24.78       
                                                                                                                        
 Sales price, net of hedging          $    71.09            $    75.07           $    69.85            $    73.88       
 Lease operating expense                   12.41                 12.69                12.46                 12.33       
 Production tax                            5.40                  5.96                 5.68                  5.62        
 General & administrative                  3.03                  3.46                 3.59                  3.43        
 Exploration                               3.22                  1.45                 1.96                  1.85        
 Cash interest expense                     2.23                  2.20                 2.17                  2.17        
 Cash income tax expense (benefit)         (0.17  )              (0.11  )             (0.02  )              0.16        
                                      $    44.97            $    49.42           $    44.01            $    48.32       
                                                                                                                        


Fourth Quarter and Full-Year 2012 Drilling and Expenditures Summary

The table below summarizes Whiting`s operated and non-operated drilling activity
and capital expenditures for the three and twelve months ended December 31,
2012:

                                                                                                      
           Gross/Net Wells Completed                                                                  
                                                   Total New          % Success        CAPEX          
           Producing          Non-Producing        Drilling           Rate             (in MM)        
 Q4 12     124 / 63.0         4 / 3.9              128 / 66.9         96.9% / 94.2%    $     574.1    
 12M 12    392 / 188.2        5 / 4.7              397 / 192.9        98.7% / 97.6%    $     2,111.5  
                                                                                                      


Outlook for First Quarter and Full-Year 2013

The following table provides guidance for the first quarter and full-year 2013
based on current forecasts, including Whiting`s full-year 2013 capital budget of
$2,200.0 million.

                                                                                               
                                                Guidance                                       
                                                First Quarter             Full-Year            
                                                2013                      2013                 
 Production (MMBOE)                             7.80 - 8.20               33.80 - 35.00        
 Lease operating expense per BOE                $ 12.50 - $ 12.90         $ 12.40 - $ 12.70    
 General and admin. expense per BOE             $ 3.40 - $ 3.60           $ 3.30 - $ 3.50      
 Interest expense per BOE                       $ 2.40 - $ 2.60           $ 2.30 - $ 2.50      
 Depr., depletion and amort. per BOE            $ 24.00 - $ 24.75         $ 24.50 - $ 25.50    
 Prod. taxes (% of production revenue)          8.4% - 8.6%               8.6% - 8.8%          
 Oil price differentials to NYMEX per Bbl(1)    ($ 6.50) - ($ 7.50)       ($ 6.50) - ($ 7.50)  
 Gas price premium to NYMEX per Mcf(2)          $ 0.20 - $ 0.50           $ 0.20 - $ 0.50      
                                                                                               


 (1)    Does not include the effect of NGLs.                                                                                               
 (2)    Includes the effect of Whiting`s fixed-price gas contracts. Please refer to fixed-price gas contracts later in this news release.  
                                                                                                                                           


Oil Hedges

The following summarizes Whiting`s crude oil hedges as of February 6, 2013:

                                                                                                            
                                                        Weighted Average                As a Percentage of  
 Derivative              Hedge     Contracted Volume    NYMEX Price Collar Range        December 2012       
 Instrument              Period    (Bbls per Month)     (per Bbl)                       Oil Production      
                                                                                                            
 Three-way Collars(1)    2013                                                                               
                         Q1        910,000              $ 70.00 - $ 85.00 - $ 114.80    42.1%               
                         Q2        1,040,000            $ 71.25 - $ 85.63 - $ 113.95    48.1%               
                         Q3        1,040,000            $ 71.25 - $ 85.63 - $ 113.95    48.1%               
                         Q4        1,040,000            $ 71.25 - $ 85.63 - $ 113.95    48.1%               
                                                                                                            
 Collars                 2013                                                                               
                         Q1        294,560              $ 48.17 - $ 90.71               13.6%               
                         Q2        294,550              $ 48.17 - $ 90.71               13.6%               
                         Q3        294,450              $ 48.16 - $ 90.70               13.6%               
                         Oct       294,340              $ 48.15 - $ 90.69               13.6%               
                         Nov       194,340              $ 47.96 - $ 85.90               9.0%                
                         Dec       4,340                $ 80.00 - $ 122.50              0.2%                
                                                                                                            
                         2014                                                                               
                         Q1        4,250                $ 80.00 - $ 122.50              0.2%                
                         Q2        4,150                $ 80.00 - $ 122.50              0.2%                
                         Q3        4,060                $ 80.00 - $ 122.50              0.2%                
                         Q4        3,970                $ 80.00 - $ 122.50              0.2%                
                                                                                                            


 (1)    A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price.  
                                                                                                                                                                                                                                                                                                                                                                                                                                                            


Whiting also has the following fixed-price natural gas contracts in place as of
February 6, 2013:

                                                                        
                                Weighted Average    As a Percentage of  
 Hedge     Contracted Volume    Contracted Price    December 2012       
 Period    (MMBtu per Month)    (per MMBtu)         Gas Production      
                                                                        
 2013                                                                   
 Q1        360,000              $5.47               15.8%               
 Q2        364,000              $5.47               15.9%               
 Q3        368,000              $5.47               16.1%               
 Q4        368,000              $5.47               16.1%               
                                                                        
 2014                                                                   
 Q1        330,000              $5.49               14.4%               
 Q2        333,667              $5.49               14.6%               
 Q3        337,333              $5.49               14.8%               
 Q4        337,333              $5.49               14.8%               
                                                                        


                                                                                                                                                
 Selected Operating and Financial Statistics                                                                                                    
                                                                                                                                                
                                                Three Months Ended                             Twelve Months Ended                              
                                                December 31,                                   December 31,                                     
                                                2012                     2011                  2012                       2011                  
 Selected operating statistics                                                                                                                  
 Production                                                                                                                                     
 Oil, MBbl                                           6,119                    4,905                 23,139                     18,299           
 NGLs, MBbl                                          711                      540                   2,766                      2,074            
 Natural gas, MMcf                                   6,522                    6,347                 25,827                     26,443           
 Oil equivalents, MBOE                               7,917                    6,503                 30,209                     24,780           
 Average Prices                                                                                                                                 
 Oil per Bbl (excludes hedging)                 $    83.50               $    88.87            $    83.86                 $    88.61            
 NGLs per Bbl                                   $    43.10               $    48.46            $    39.36                 $    52.38            
 Natural gas per Mcf (excludes hedging)         $    3.60                $    4.72             $    3.42                  $    4.92             
 Per BOE Data                                                                                                                                   
 Sales price (including hedging)                $    71.09               $    75.07            $    69.85                 $    73.88            
 Lease operating                                $    12.41               $    12.69            $    12.46                 $    12.33            
 Production taxes                               $    5.40                $    5.96             $    5.68                  $    5.62             
 Depreciation, depletion and amortization       $    23.80               $    19.58            $    22.67                 $    18.89            
 General and administrative (1)                 $    3.03                $    3.46             $    3.59                  $    3.43             
 Selected Financial Data                                                                                                                        
 (In thousands, except per share data)                                                                                                          
 Total revenues and other income                $    577,090             $    498,637          $    2,173,452             $    1,899,622        
 Total costs and expenses                       $    447,033             $    400,434          $    1,511,441             $    1,119,303        
 Net income available to common shareholders    $    81,434              $    62,620           $    413,112               $    490,610          
 Earnings per common share, basic               $    0.69                $    0.54             $    3.51                  $    4.18             
 Earnings per common share, diluted             $    0.69                $    0.53             $    3.48                  $    4.14             
                                                                                                                                                
 Average shares outstanding, basic                   117,631                  117,381               117,601                    117,345          
 Average shares outstanding, diluted                 118,992                  118,644               119,028                    118,668          
 Net cash provided by operating activities      $    383,270             $    328,329          $    1,401,215             $    1,192,083        
 Net cash used in investing activities          $    (559,160  )         $    (493,156  )      $    (1,780,318  )         $    (1,760,036  )    
 Net cash provided by financing activities      $    194,615             $    174,550          $    408,092               $    564,812          
                                                                                                                                                


 (1)    For the twelve months ended December 31, 2012, the price includes the effect of a one-time charge under our Production Participation Plan related to the Whiting USA Trust II divestiture of $0.28 per BOE.  
                                                                                                                                                                                                                     


Conference Call

The Company`s management will host a conference call with investors, analysts
and other interested parties on Thursday, February 28, 2013 at 11:00 a.m. EST
(10:00 a.m. CST, 9:00 a.m. MST) to discuss Whiting`s fourth quarter and
full-year 2012 financial and operating results. Please call (800) 591-6923
(U.S./Canada) or (617) 614-4907 (International) to be connected to the call and
enter the pass code 31942801. Access to a live internet broadcast will be
available at http://www.whiting.com by clicking on the "Investor Relations" box
on the menu and then on the link titled "Webcasts." Slides for the conference
call will be available on this website beginning at 11:00 a.m. (EST) on February
28, 2013. 

A telephonic replay will be available beginning approximately two hours after
the call on Thursday, February 28, 2013 and continuing through Thursday, March
7, 2013. You may access this replay at (888) 286-8010 (U.S./Canada) or (617)
801-6888 (International) and entering the pass code 50698820. You may also
access a web archive at http://www.whiting.com beginning approximately one hour
after the conference call. 

About Whiting Petroleum Corporation

Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and
gas company that explores for, develops, acquires and produces crude oil,
natural gas and natural gas liquids primarily in the Rocky Mountain, Permian
Basin, Mid-Continent, Michigan and Gulf Coast regions of the United States. The
Company`s largest projects are in the Bakken and Three Forks plays in North
Dakota and its Enhanced Oil Recovery fields in Oklahoma and Texas. The Company
trades publicly under the symbol WLL on the New York Stock Exchange. For further
information, please visit http://www.whiting.com. 

Forward-Looking Statements

This news release contains statements that we believe to be "forward-looking
statements" within the meaning of the Private Securities Litigation Reform Act
of 1995. All statements other than historical facts, including, without
limitation, statements regarding our future financial position, business
strategy, projected revenues, earnings, costs, capital expenditures and debt
levels, and plans and objectives of management for future operations, are
forward-looking statements. When used in this news release, words such as we
"expect," "intend," "plan," "estimate," "anticipate," "believe" or "should" or
the negative thereof or variations thereon or similar terminology are generally
intended to identify forward-looking statements. Such forward-looking statements
are subject to risks and uncertainties that could cause actual results to differ
materially from those expressed in, or implied by, such statements. 

These risks and uncertainties include, but are not limited to: declines in oil,
NGL or natural gas prices; our level of success in exploration, development and
production activities; adverse weather conditions that may negatively impact
development or production activities; the timing of our exploration and
development expenditures; our ability to obtain sufficient quantities of CO2
necessary to carry out our enhanced oil recovery projects; inaccuracies of our
reserve estimates or our assumptions underlying them; revisions to reserve
estimates as a result of changes in commodity prices; risks related to our level
of indebtedness and periodic redeterminations of the borrowing base under our
credit agreement; our ability to generate sufficient cash flows from operations
to meet the internally funded portion of our capital expenditures budget; our
ability to obtain external capital to finance exploration and development
operations and acquisitions; federal and state initiatives relating to the
regulation of hydraulic fracturing; the potential impact of federal debt
reduction initiatives and tax reform legislation being considered by the U.S.
Federal government that could have a negative effect on the oil and gas
industry; impacts of the global recession and tight credit markets; our ability
to identify and complete acquisitions and to successfully integrate acquired
businesses; unforeseen underperformance of or liabilities associated with
acquired properties; our ability to successfully complete potential asset
dispositions and the risks related thereto; the impacts of hedging on our
results of operations; failure of our properties to yield oil or gas in
commercially viable quantities; uninsured or underinsured losses resulting from
our oil and gas operations; our inability to access oil and gas markets due to
market conditions or operational impediments; the impact and costs of compliance
with laws and regulations governing our oil and gas operations; our ability to
replace our oil and natural gas reserves; any loss of our senior management or
technical personnel; competition in the oil and gas industry in the regions in
which we operate; risks arising out of our hedging transactions; and other risks
described under the caption "Risk Factors" in our Annual Report on Form 10-K for
the period ended December 31, 2012. We assume no obligation, and disclaim any
duty, to update the forward-looking statements in this news release. 

Disclosure Regarding Reserves and Resources

Whiting uses in this news release 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 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 news release 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 resourcesare
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. 

SELECTED FINANCIAL DATA

For further information and discussion on the selected financial data below,
please refer to Whiting Petroleum Corporation`s Annual Report on Form 10-K for
the year ended December 31, 2012, to be filed with the Securities and Exchange
Commission.

                                                                                                                    
 WHITING PETROLEUM CORPORATION                                                                                      
 CONSOLIDATED BALANCE SHEETS (Unaudited)                                                                            
 (In thousands)                                                                                                     
                                                                                                                    
                                                              December 31,                December 31,              
                                                              2012                        2011                      
 ASSETS                                                                                                             
                                                                                                                    
 Current assets:                                                                                                    
 Cash and cash equivalents                                    $      44,800               $      15,811             
 Accounts receivable trade, net                                      318,265                     262,515            
 Prepaid expenses and other                                          21,347                      20,377             
 Total current assets                                                384,412                     298,703            
                                                                                                                    
 Property and equipment:                                                                                            
 Oil and gas properties, successful efforts method:                                                                 
 Proved properties                                                   8,849,515                   7,221,550          
 Unproved properties                                                 362,483                     354,774            
 Other property and equipment                                        141,738                     150,933            
 Total property and equipment                                        9,353,736                   7,727,257          
 Less accumulated depreciation, depletion and amortization           (2,590,203  )               (2,088,517  )      
 Total property and equipment, net                                   6,763,533                   5,638,740          
                                                                                                                    
 Debt issuance costs                                                 28,748                      33,306             
                                                                                                                    
 Other long-term assets                                              95,726                      74,860             
                                                                                                                    
 TOTAL ASSETS                                                 $      7,272,419            $      6,045,609          
                                                                                                                    


                                                                                                                                                                                                                                                                                                           
 WHITING PETROLEUM CORPORATION                                                                                                                                                                                                                                                                             
 CONSOLIDATED BALANCE SHEETS (Unaudited)                                                                                                                                                                                                                                                                   
 (In thousands, except share and per share data)                                                                                                                                                                                                                                                           
                                                                                                                                                                                                                                                                                                           
                                                                                                                                                                                                                                                       December 31,               December 31,             
                                                                                                                                                                                                                                                       2012                       2011                     
 LIABILITIES AND EQUITY                                                                                                                                                                                                                                                                                    
                                                                                                                                                                                                                                                                                                           
 Current liabilities:                                                                                                                                                                                                                                                                                      
 Accounts payable trade                                                                                                                                                                                                                                $      131,370             $      56,673            
 Accrued capital expenditures                                                                                                                                                                                                                                 110,663                    142,827           
 Accrued liabilities and other                                                                                                                                                                                                                                180,622                    157,214           
 Revenues and royalties payable                                                                                                                                                                                                                               149,692                    103,894           
 Taxes payable                                                                                                                                                                                                                                                33,283                     31,195            
 Derivative liabilities                                                                                                                                                                                                                                       21,955                     73,647            
 Deferred income taxes                                                                                                                                                                                                                                        9,394                      1,584             
 Total current liabilities                                                                                                                                                                                                                                    636,979                    567,034           
 Long-term debt                                                                                                                                                                                                                                               1,800,000                  1,380,000         
 Deferred income taxes                                                                                                                                                                                                                                        1,063,681                  823,643           
 Derivative liabilities                                                                                                                                                                                                                                       1,678                      47,763            
 Production Participation Plan liability                                                                                                                                                                                                                      94,483                     80,659            
 Asset retirement obligations                                                                                                                                                                                                                                 86,179                     61,984            
 Deferred gain on sale                                                                                                                                                                                                                                        110,395                    29,619            
 Other long-term liabilities                                                                                                                                                                                                                                  25,852                     25,776            
 Total liabilities                                                                                                                                                                                                                                            3,819,247                  3,016,478         
 Commitments and contingencies                                                                                                                                                                                                                                                                             
 Equity:                                                                                                                                                                                                                                                                                                   
 Preferred stock, $0.001 par value, 5,000,000 shares authorized; 6.25% convertible perpetual preferred stock, 172,391 issued and outstanding as of December 31, 2012 and 2011, aggregate liquidation preference of $17,239,100 at December 31, 2012           -                          -                 
 Common stock, $0.001 par value, 300,000,000 shares authorized; 118,582,477 issued and 117,631,451 outstanding as of December 31, 2012, 118,105,279 issued and 117,380,884 outstanding as of December 31, 2011                                                119                        118               
 Additional paid-in capital                                                                                                                                                                                                                                   1,566,717                  1,554,223         
 Accumulated other comprehensive income (loss)                                                                                                                                                                                                                (1,236     )               240               
 Retained earnings                                                                                                                                                                                                                                            1,879,388                  1,466,276         
 Total Whiting shareholders` equity                                                                                                                                                                                                                           3,444,988                  3,020,857         
 Noncontrolling interest                                                                                                                                                                                                                                      8,184                      8,274             
 Total equity                                                                                                                                                                                                                                                 3,453,172                  3,029,131         
                                                                                                                                                                                                                                                                                                           
 TOTAL LIABILITIES AND EQUITY                                                                                                                                                                                                                          $      7,272,419           $      6,045,609         
                                                                                                                                                                                                                                                                                                           


                                                                                                                                                  
 WHITING PETROLEUM CORPORATION                                                                                                                    
 CONSOLIDATED STATEMENTS OF INCOME (Unaudited)                                                                                                    
 (In thousands, except per share data)                                                                                                            
                                                                                                                                                  
                                                      Three Months Ended                           Twelve Months Ended                            
                                                      December 31,                                 December 31,                                   
                                                      2012                    2011                 2012                      2011                 
 REVENUES AND OTHER INCOME:                                                                                                                       
 Oil, NGL and natural gas sales                       $    565,066            $    492,025         $    2,137,714            $    1,860,146       
 Gain on hedging activities                                54                      1,432                2,338                     8,758           
 Amortization of deferred gain on sale                     8,177                   3,482                29,458                    13,937          
 Gain on sale of properties                                3,686                   1,581                3,423                     16,313          
 Interest income and other                                 107                     117                  519                       468             
 Total revenues and other income                           577,090                 498,637              2,173,452                 1,899,622       
                                                                                                                                                  
 COSTS AND EXPENSES:                                                                                                                              
 Lease operating                                           98,271                  82,550               376,424                   305,487         
 Production taxes                                          42,732                  38,778               171,625                   139,190         
 Depreciation, depletion and amortization                  188,428                 127,335              684,724                   468,203         
 Exploration and impairment                                87,610                  23,318               166,972                   84,644          
 General and administrative                                23,962                  22,515               108,573                   84,985          
 Interest expense                                          20,115                  16,649               75,210                    62,516          
 Change in Production Participation Plan liability         7,625                   (3,925   )           13,824                    (865       )    
 Commodity derivative (gain) loss, net                     (21,710  )              93,214               (85,911    )              (24,857    )    
 Total costs and expenses                                  447,033                 400,434              1,511,441                 1,119,303       
                                                                                                                                                  
 INCOME BEFORE INCOME TAXES                                130,057                 98,203               662,011                   780,319         
                                                                                                                                                  
 INCOME TAX EXPENSE (BENEFIT):                                                                                                                    
 Current                                                   (1,345   )              (737     )           (669       )              3,853           
 Deferred                                                  49,713                  36,110               248,581                   284,838         
 Total income tax expense                                  48,368                  35,373               247,912                   288,691         
                                                                                                                                                  
 NET INCOME                                                81,689                  62,830               414,099                   491,628         
 Net loss attributable to noncontrolling interest          14                      59                   90                        59              
                                                                                                                                                  
 NET INCOME AVAILABLE TO SHAREHOLDERS                      81,703                  62,889               414,189                   491,687         
 Preferred stock dividends                                 (269     )              (269     )           (1,077     )              (1,077     )    
                                                                                                                                                  
 NET INCOME AVAILABLE TO COMMON SHAREHOLDERS          $    81,434             $    62,620          $    413,112              $    490,610         
                                                                                                                                                  
 EARNINGS PER COMMON SHARE:                                                                                                                       
 Basic                                                $    0.69               $    0.54            $    3.51                 $    4.18            
 Diluted                                              $    0.69               $    0.53            $    3.48                 $    4.14            
                                                                                                                                                  
 WEIGHTED AVERAGE SHARES OUTSTANDING:                                                                                                             
 Basic                                                     117,631                 117,381              117,601                   117,345         
 Diluted                                                   118,992                 118,644              119,028                   118,668         
                                                                                                                                                  


                                                                                                                                                                             
 WHITING PETROLEUM CORPORATION                                                                                                                                               
 Reconciliation of Net Income Available to Common Shareholders to                                                                                                            
 Adjusted Net Income Available to Common Shareholders                                                                                                                        
 (In thousands, except for per share data)                                                                                                                                   
                                                                                                                                                                             
                                                                                     Three Months Ended                           Twelve Months Ended                        
                                                                                     December 31,                                 December 31,                               
                                                                                     2012                    2011                 2012                    2011               
 Net Income Available to Common Shareholders                                         $    81,434             $    62,620          $    413,112            $    490,610       
                                                                                                                                                                             
 Adjustments Net of Tax:                                                                                                                                                     
 Amortization of Deferred Gain on Sale                                                    (5,136   )              (2,227   )           (18,427  )              (8,781   )    
 Gain on Sale of Properties                                                               (2,315   )              (1,012   )           (2,141   )              (10,278  )    
 Impairment Expense                                                                       38,996                  8,869                67,465                  24,435        
 One-time Charge Under Production Participation Plan Related to Trust II Offering         -                       -                    5,930                   -             
 Unrealized Derivative (Gains) Losses                                                     (15,056  )              56,273               (72,393  )              (39,751  )    
 Adjusted Net Income (1)                                                             $    97,923             $    124,523         $    393,546            $    456,235       
                                                                                                                                                                             
 Adjusted Net Income Available to Common Shareholders per Share, Basic               $    0.83               $    1.06            $    3.35               $    3.89          
 Adjusted Net Income Available to Common Shareholders per Share, Diluted             $    0.83               $    1.05            $    3.31               $    3.85          
                                                                                                                                                                             


 (1)    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 U.S. GAAP and may not be comparable to other similarly titled measures of other companies.                                                                 
                                                                                                                                                                                  


                                                                                                                                          
 WHITING PETROLEUM CORPORATION                                                                                                            
 Reconciliation of Net Cash Provided by Operating Activities to Discretionary Cash Flow                                                   
 (In thousands)                                                                                                                           
                                                                                                                                          
                                              Three Months Ended                           Twelve Months Ended                            
                                              December 31,                                 December 31,                                   
                                              2012                    2011                 2012                      2011                 
                                                                                                                                          
 Net cash provided by operating activities    $    383,270            $    328,329         $    1,401,215            $    1,192,083       
 Exploration                                       25,525                  9,455                59,117                    45,861          
 Exploratory dry hole costs                        (16,288  )              (210     )           (18,428    )              (4,924     )    
 Changes in working capital                        (10,513  )              (8,496   )           (53,318    )              10,762          
 Preferred stock dividends paid                    (269     )              (269     )           (1,077     )              (1,077     )    
 Discretionary cash flow (1)                  $    381,725            $    328,809         $    1,387,509            $    1,242,705       
                                                                                                                                          


 (1)    Discretionary cash flow is computed as net income plus exploration and impairment costs, depreciation, depletion and amortization, deferred income taxes, non-cash        
        interest costs, non-cash compensation plan charges, non-cash losses on mark-to-market derivatives and other non-current 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. The non-GAAP measure of discretionary cash flow  
        is presented because management believes it provides useful information to investors for analysis of the Company`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 U.S. GAAP and may not be comparable to other similarly titled measures of other companies.              


Whiting Petroleum Corporation
John B. Kelso, 303-837-1661
Director of Investor Relations
john.kelso@whiting.com

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