Whiting Petroleum Corporation Announces Fourth Quarter and Full-Year 2011 Financial and Operating Results

2011 Production: A Record 24.8 MMBOE (67,890 BOE/d)

2011 Proved Reserves: Up 13.2% to a Record 345.2 MMBOE Replaces 274% of 2011 Production

Q4 2011 Net Income Available to Common Shareholders of $62.6 Million or $0.53 per Diluted Share and Adjusted Net Income of $124.5 Million or $1.05 per Diluted Share

Q4 2011 Discretionary Cash Flow Totals a Record $328.8 Million

2012 Capital Budget of $1.6 Billion for 242 Gross (148 Net) Wells

January 2012 Production Averages over 76,000 BOE/d

Increasing Q1 and FY 2012 Production Guidance to 6.8 - 7.2 MMBOE and 28.3 - 29.7 MMBOE (+14% to 20% YoY)

DENVER--(BUSINESS WIRE)--Whiting Petroleum Corporation’s (NYSE: WLL) production in the fourth quarter of 2011 totaled a record 6.50 million barrels of oil equivalent (MMBOE), of which 5.45 million barrels were crude oil/natural gas liquids (84%) and 1.05 MMBOE was natural gas (16%). This fourth quarter 2011 production total equates to a new record daily average production rate of 70,685 barrels of oil equivalent (BOE), which compared to an average daily rate of 67,900 BOE in the fourth quarter of 2010. Production of 73,240 BOE per day in December 2011 represented a 3% increase over the 71,370 BOE per day average rate in September 2011.

Production in 2011 totaled a record 24.8 MMBOE, or an average of 67,890 BOE per day, compared to 23.6 MMBOE, or an average of 64,650 BOE per day, in 2010. The 5% increase in production for 2011 versus 2010 was primarily the result of organic production growth in the North Dakota Bakken and Three Forks formations as well as the continued response from Whiting’s CO₂ enhanced oil recovery (EOR) projects.

In January 2012 our production averaged more than 76,000 BOE per day as we experienced exceptional drilling results and brought on line an additional 11 shut-in wells in our Sanish field. We have increased our first quarter 2012 production guidance to a range of 75,700 – 79,100 BOE per day from the prior range of 72,500 – 74,700 BOE per day. We have also increased our full-year 2012 production guidance to a range of 77,300 – 81,100 BOE per day, up from our prior range of 76,500 – 80,600 BOE per day. Our revised guidance for 2012 translates into an estimated production increase of between 14% and 20% over 2011. This production guidance does not consider the impact of the announced offering of Whiting USA Trust II, which is projected to produce approximately 1,467 MBOE for the full-year 2012 based on the trust’s projected 90% ownership of the underlying properties.

Operating and Financial Results

The following tables summarize the fourth quarter and full-year operating and financial results for 2011 and 2010.

Three Months Ended December 31,^(1)
	2011	2010	Change
Production (MMBOE/MBOE/d)	6.50/70.69	6.25/67.90	4%
Discretionary Cash Flow-MM$ ^(2)	328.8	277.2	19%
Total Revenues-MM$	498.6	413.5	21%
Net Income Available to Shareholders-MM$	62.6	65.9	(5%)
Per Basic Share	$0.54	$0.56	(5%)
Per Diluted Share	$0.53	$0.56	(5%)
Adjusted Net Income Available to Common Shareholders-MM$ ^(3)	124.5	99.0	26%
Per Basic Share	$1.06	$0.85	25%
Per Diluted Share	$1.05	$0.84	25%

Twelve Months Ended December 31, ^(1)
	2011	2010	Change
Production (MMBOE/MBOE/d)	24.78/67.89	23.60/64.65	5%
Discretionary Cash Flow-MM$ ^(2)	1,242.7	949.3	31%
Total Revenues-MM$	1,899.6	1,516.1	25%
Net Income Available to Shareholders-MM$	490.6	272.7	80%
Per Basic Share	$ 4.18	$2.57	63%
Per Diluted Share	$ 4.14	$2.55	62%
Adjusted Net Income Available to Common Shareholders-MM$ ^(3)	456.2	304.7	50%
Per Basic Share	$3.89	$2.99	30%
Per Diluted Share	$3.85	$2.71	42%

⁽¹⁾ Restated for the 2010 period to reflect the Company’s February 22, 2011 two-for-one stock split.
⁽²⁾ A reconciliation of discretionary cash flow to net cash provided by operating activities is included later in this news release.
⁽³⁾ 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, 2011

As of December 31, 2011, Whiting had estimated proved reserves of 345.2 MMBOE, of which 69% were classified as proved developed. These estimated proved reserves had a pre-tax PV10% value of $7,404.7 million, of which approximately 97% came from properties located in Whiting’s Rocky Mountain, Permian Basin and Mid-Continent core areas. The following table summarizes by core area, Whiting’s estimated proved reserves as of December 31, 2011, their corresponding pre-tax PV10% values and the fourth quarter 2011 average daily production rates:

	Proved Reserves ^(1)						Q4 2011 Average Daily Production (MBOE/d)
Core Area	Oil (MMBbl)^(2)	Natural Gas (Bcf)	Total (MMBOE)	% Oil^(2)	Pre-Tax PV10% Value^(3) (In MM)
Rocky Mountains	132.2	162.3	159.2	83%	$	4,157.1	44.4
Permian Basin	122.5	38.1	128.8	95%	$	2,011.6	13.4
Other^(4)	43.1	84.6	57.2	75%	$	1,236.0	12.9
Total	297.8	285.0	345.2	86%	$	7,404.7	70.7

^(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, 2011, pursuant to current SEC and FASB guidelines. The NYMEX prices used were $96.19/Bbl and $4.12/MMBtu.
^(2)	Oil includes natural gas liquids.
^(3)	Pre-tax PV10% 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, 2011, our discounted future income taxes were $2,132.2 million and our standardized measure of after-tax discounted future net cash flows was $5,272.5 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.
^(4)	Other consists of Mid-Continent, Michigan, and Gulf Coast.

The following is a summary of Whiting’s changes in quantities of proved oil and gas reserves for the year ended December 31, 2011:

	Oil (MBbl)	Natural Gas (MMcf)	Total (MBOE)
Balance – December 31, 2010	254,278	303,544	304,869
Extensions and discoveries	44,684	23,211	48,552
Sales of minerals in place	(1,211)	(9,759)	(2,837)
Purchases of minerals in place	172	1,639	445
Production	(20,373)	(26,443)	(24,780)
Revisions to previous estimates	20,203	(7,217)	19,000 ^(1)
Balance – December 31, 2011	297,753	284,975	345,249

⁽¹⁾ Whiting has experienced positive reserve revisions in each of the last three years (2009-2011). Of the 19.0 MMBOE of upward revisions in 2011, 4.7 MMBOE were due to commodity prices and 14.3 MMBOE were the result of reservoir analysis and well performance. The liquids component of the net 14.3 MMBOE revision consisted of a 15.7 MMBOE increase that was primarily related to our Postle and North Ward Estes fields where performance of the EOR projects supported an increase in proved reserves. The gas component of the net 14.3 MMBOE revision consisted of a 1.4 MMBOE decrease due to production performance of two wells in our Flat Rock field.

Whiting’s proved reserves of 345.2 MMBOE represented a 13.2% increase over the 304.9 MMBOE of proved reserves at year-end 2010. An estimated 48.6 MMBOE of proved reserves were added through exploration and development activities. In total, Whiting replaced 274% of its 2011 production of 24.8 MMBOE at an all-in finding and development cost of $27.09 per BOE, which includes $230.6 million in facilities and $186.9 million of land expenditures. The table at the end of this news release summarizes Whiting’s all-in finding and development costs and reserve replacement for the three-year period ended December 31, 2011.

Most of the proved reserve additions during 2011 came from the Company’s Bakken and Three Forks development in the Williston Basin of North Dakota and Montana. Whiting booked an estimated 45.1 MMBOE of new Bakken and Three Forks proved reserves, bringing its total proved reserves in the Northern Rockies to 128.6 MMBOE at year-end 2011. Of this 128.6 MMBOE, 69% were proved developed and 31% were proved undeveloped.

Probable and Possible Reserves at December 31, 2011

At year-end 2011, Whiting’s probable reserves were estimated to be 105.9 MMBOE and our possible reserves were estimated to be 195.3 MMBOE, for a total of 301.2 MMBOE. The year-end 2011 estimated pre-tax PV10% for our probable and possible reserves was $3,059.2 million, representing a 27% increase over the $2,415.2 million at year-end 2010.

The EOR project at our North Ward Estes field represented 115.5 MMBOE of the 301.2 MMBOE total, or 38%. The other primary contributors to Whiting’s probable and possible reserve estimates were additional Bakken and Three Forks reserves in the Williston Basin with 71.0 MMBOE. 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 tables summarize Whiting’s estimated probable and possible reserves as of December 31, 2011 by core area and the corresponding pre-tax PV10% values.

	Probable Reserves ^(1)
Core Area	Oil (MMBbl)^(2)	Natural Gas (Bcf)	Total (MMBOE)	%	Pre-Tax PV10% Value^(3)
				Oil^(2)	(In MM)
Rocky Mountains	24.7	133.5	46.9	53%	$	374.9
Permian Basin	36.9	53.0	45.8	81%	$	576.6
Other^(4)	9.2	24.4	13.2	69%	$	83.9
Total	70.8	210.9	105.9	67%	$	1,035.4
	Possible Reserves ^(1)
Core Area	Oil (MMBbl)^(2)	Natural Gas (Bcf)	Total (MMBOE)	%		Pre-Tax PV10% Value^(3)
				Oil^(2)		(In MM)
Rocky Mountains	59.2	150.0	84.3	70%	$	1,086.9
Permian Basin	101.9	8.9	103.3	99%	$	861.0
Other^(4)	3.0	28.3	7.7	39%	$	75.9
Total	164.1	187.2	195.3	84%	$	2,023.8

^(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, 2011, pursuant to SEC and FASB guidelines. The NYMEX prices used were $96.19/Bbl and $4.12/MMBtu.
^(2)	Oil includes natural gas liquids.
^(3)	Pre-tax PV10% amounts above 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.
^(4)	Other consists of Mid-Continent, Michigan, and Gulf Coast.

Resource Potential at December 31, 2011

Whiting has internally estimated its unrisked total resource potential to be 479 MMBOE at year-end 2011, representing a 28% increase from the 374 MMBOE estimate at year-end 2010. The largest contributor to this 479 MMBOE total was continued Bakken and Three Forks exploration in North Dakota and Montana with 180 MMBOE. The year-end 2011 estimated PV10% for our resource potential was $4,734 million, representing a 12% increase over the $4,238 million at year-end 2010. Please refer to “Disclosure Regarding Reserves and Resources” later in this news release for information on resource potential.

The following table summarizes Whiting’s estimated resource potential as of December 31, 2011 by core area and the corresponding pre-tax PV10%.

	Resource Potential ^(1)
Core Area	Oil (MMBbl)^(2)	Natural Gas (Bcf)	Total (MMBOE)	%	Pre-Tax PV10% Value^(3)
				Oil^(2)	(In MM)
Rocky Mountains	297.4	506.7	381.9	78%	$	3,944.9
Permian Basin	59.9	86.1	74.2	81%	$	706.8
Other	7.4	91.8	22.6	32%	$	82.2
Total	364.7	684.6	478.7	76%	$	4,733.9

^(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, 2011, pursuant to SEC and FASB guidelines. The NYMEX prices used were $96.19/Bbl and $4.12/MMBtu.
^(2)	Oil includes natural gas liquids.
^(3)	Pre-tax PV10% amounts above represent the present value of estimated future revenues to be generated from the production of resource potential 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% values of resource potential reserves, there do not exist any directly comparable US GAAP measures and such amounts do not purport to present the fair value of our resource potential reserves.
^(4)	Other consists of Mid-Continent, Michigan, and Gulf Coast.

Total Drilling Locations at December 31, 2011

Based on independent engineering, Whiting has a total of 2,264 proved, probable and possible gross drilling locations. Of these, 31% are located in its core Northern Rockies Region, which includes Whiting’s Bakken/Three Forks projects in the Williston Basin. In addition, the Company estimates it has 3,741 gross resource locations across its company-wide acreage position. Of these, 49% are located in Whiting’s core Northern Rockies Region, which includes its Bakken/Three Forks projects in the Williston Basin.

The following tables summarize our potential gross and net drilling locations by core region from our proved, probable and possible reserves and our resource potential:

Total 3P Drilling Locations
	Gross	Net
Northern Rockies	707	334
Central Rockies	421	283
Permian Basin	838	338
Mid-Continent	210	189
Gulf Coast	72	58
Michigan	16	13
Total	2,264	1,215

Total Resource Drilling Locations
	Gross	Net
Northern Rockies	1,839	640
Central Rockies	1,416	889
Permian Basin	417	307
Mid-Continent	6	1
Gulf Coast	34	31
Michigan	29	22
Total	3,741	1,890

James J. Volker, Whiting’s Chairman and CEO, commented, “2011 was a year of discoveries for Whiting Petroleum. We de-risked a substantial portion of our acreage at Lewis & Clark/Pronghorn and generated excellent initial drilling results at Hidden Bench/Tarpon. Our 2011 drilling program sets the table for what we believe will be a strong year for production and reserves growth in 2012. Based on independent engineering at December 31, 2011, we had 2,264 gross locations from our 3P reserves. Based on internal estimates at year-end 2011, we had an additional 3,741 gross locations estimated from our resource potential.”

Mr. Volker continued, “In 2012, we will focus on bringing a number of our prospects into development mode. These prospects include Hidden Bench/Tarpon and Missouri Breaks. We also plan further development of our resource play at Lewis & Clark/Pronghorn. With these key projects, we are optimistic about Whiting’s operational results in 2012. We will continue to focus on oil in the foreseeable future. Currently, crude oil trades at more than 40 times the price of natural gas, which compares to their 6 to 1 heating equivalency ratio. At year-end 2011, 86% of our proved reserves and 84% of our production consisted of oil and natural gas liquids. We expect that percentage to continue to increase over the next several years.”

2012 Capital Budget

Our 2012 capital budget is $1,600 million, which we expect to fund substantially with net cash provided by our operating activities. Whiting expects to invest $1,236 million of the 2012 capital budget in exploration and development activity, $136 million for land, and $228 million for facilities. Based on this level of capital spending, we forecast production of 28.3 MMBOE - 29.7 MMBOE for 2012, an increase of 14% - 20% over our 2011 production of 24.8 MMBOE.

Our 2012 capital budget is currently allocated among our major development areas as indicated in the table below:

	2012 CAPEX (MM)		Gross Wells	Net Wells	% of Total
Northern Rockies	$	851	218	124	53%
EOR		177	NA^(2)	NA^(2)	11%
Permian		60	13	13	4%
Central Rockies		50	11	11	3%
Non-Operated		42			3%
Land		136			9%
Exploration Expense ^(1)		56			3%
Facilities		228			14%
Total Budget	$	1,600	242	148	100%

^(1)	Comprised primarily of exploration salaries, seismic activities and delay rentals.
^(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.

The following table breaks out our 2012 capital budget by category:

	2012 CAPEX (MM)		% of Total
Development Drilling	$	892	56%
Facilities		229	14%
Exploration Drilling		144	9%
Land		136	9%
CO2 Purchases		83	5%
Workovers		49	3%
Seismic		16	1%
Other ^(1)		51	3%
Total	$	1,600	100%

⁽¹⁾ Includes $40 million of exploration expense primarily for exploration salaries and delay rentals.

Operations Update

Williston Basin Overview

Whiting is one of the largest oil and gas producers in North Dakota. We ranked first in total production per well during the first six months based on information from IHS Energy, Inc. and the NDIC, with an average first six months production of 91,000 BOE. This average was 6,000 BOE higher than the second ranked Bakken operator and 30,000 BOE better than the average of the next 25 operators. We have achieved these rankings while having some of the lowest completed well costs in our Bakken peer group. We are currently drilling and completing wells in the Sanish field for approximately $6.0 million. Outside of Sanish, in other North Dakota areas, our completed well costs are currently running between $6.0 and $8.0 million and declining as we move into development mode. In addition, our average lease cost in the Williston Basin, where we hold 681,504 net acres in the Bakken/Three Forks Hydrocarbon System, is $432 per net acre.

In 2012, we plan to invest $851 million for the drilling and completion of 218 gross (124 net) wells in the Williston Basin. This represents 69% of our total planned exploration and development expenditures of $1,236 million. We have initiated pad drilling at our Sanish field and our Lewis & Clark/Pronghorn prospects. We expect to drill two or three wells off of each pad at Sanish and, for the most part, two wells off of each pad at Lewis & Clark/Pronghorn. We currently estimate that we can save approximately $500,000 per well in mobilization costs and efficiencies utilizing pad drilling.

We currently have 21 drilling rigs operating in the Williston Basin. We have 33 service rigs running in the Basin, which is up from 20 at September 22, 2011, and three full-time dedicated frac crews. As of February 1, 2012, there were 292 Whiting-operated wells producing, 46 operated wells being completed or awaiting completion, 16 wells were being drilled and 31 wells were shut-in awaiting workover operations.

Core Development Areas

Bakken and Three Forks Development

Lewis & Clark/Pronghorn Prospects. Whiting’s net production from the Lewis & Clark/Pronghorn prospects averaged 5,870 BOE per day in the fourth quarter of 2011, up 48% from the 3,960 BOE per day average in the third quarter of 2011. We currently have six drilling rigs operating in the Pronghorn prospect and two drilling rigs running in the Lewis & Clark prospect. We own 385,665 gross (256,296 net) acres in the Lewis & Clark/Pronghorn prospects, which is three and a half times the area of Sanish field.

The following table summarizes our results from inception to December 31, 2011 from the Pronghorn Sand/Three Forks at Lewis & Clark/Pronghorn:

Lewis & Clark/Pronghorn Total Wells^(1)
	Avg WI %	Avg NRI %	Avg IP BOE/d 24-hr Test	Avg 1st 30 Day	Avg 1st 60 Day	Avg 1st 90 Day
No. of Wells	44	44	44	41	37	33
Averages	79%	63%	1,312	565	435	376

⁽¹⁾ Excludes five delineation wells drilled outside the reservoir boundary.

The following table highlights some notable Pronghorn Prospect wells completed in the Pronghorn Sand during the fourth quarter of 2011 and to date in the first quarter of 2012:

Well Name	WI	NRI	IP (BOE/d)
			24-Hour Test
Obrigewitch 21-16TFH	89%	71%	3,373
Pronghorn Federal 21-13TFH	99%	79%	3,255
Mastel 41-18TFH	77%	61%	3,218
DRS Federal 24-24TFH	87%	69%	2,898
Frank 34-7TFH	90%	72%	2,811
Marsh 21-16TFH-R	82%	66%	2,694
Buresh 34-10TFH	44%	35%	2,171
Pronghorn Federal 21-14TFH	53%	42%	1,849
Obrigewitch 11-17TFH	96%	77%	1,740
Pronghorn Federal 34-11TFH	100%	80%	1,645
Averages	82%	65%	2,565

Hidden Bench/Tarpon Prospects. Whiting’s net production from the Hidden Bench prospect averaged 1,765 BOE per day, more than double the 855 BOE per day rate in the third quarter of 2011. We currently hold 59,894 gross (29,354 net) acres in the prospect, which is located in McKenzie County, North Dakota.

Whiting’s first well at the Tarpon prospect set a new initial production record for all Bakken wells drilled in the Williston Basin. The Tarpon Federal 21-4H well was completed in the Middle Bakken (after a 30 stage sliding sleeve frac job) flowing 4,815 barrels of oil and 13,163 Mcf of gas (7,009 BOE) per day on October 17, 2011. As of December 31, 2011, the well was producing 1,528 BOE per day. The Company owns a 56% working interest and a 45% net revenue interest in the Tarpon well. Whiting drilling engineers and field personnel also set a new Tarpon Prospect area record by drilling this well to total depth in 13.3 days. Whiting holds 8,125 gross (6,265 net) acres at the Tarpon prospect, which is located in McKenzie County, North Dakota. We have the potential to drill a total of 12 Middle Bakken and eight Three Forks wells on this prospect. We expect to resume drilling at Tarpon in June 2012, subject to federal permitting.

The following table summarizes our results from inception to December 31, 2011 from the Hidden Bench/Tarpon prospects:

Hidden Bench/Tarpon Total Wells
	Avg WI %	Avg NRI %	Avg IP BOE/d 24-hr Test	Avg 1st 30 Day	Avg 1st 60 Day	Avg 1st 90 Day
No. of Wells	8	8	8	5	3	3
Averages	68%	55%	2,904	941	1,040	930

Missouri Breaks Prospect. In our Missouri Breaks prospect, we target the same Middle Bakken “C” zone that we target at our Hidden Bench/Tarpon prospects. We have initiated a one-rig drilling program in the play. We hold 58,840 gross (40,290 net) acres in the prospect and have controlling interests in 46 1,280-acre spacing units. Subsequent to year-end, we entered into a contract to add 51,200 gross (13,300 net) acres in the prospect. This transaction is expected to close in March 2012. Missouri Breaks is located in Richland County, Montana.

Sanish Field. During the fourth quarter, Whiting completed 19 gross operated wells at Sanish, bringing the total number of producing wells in the field to 218. The following table summarizes the Company’s operated and non-operated net production from the Sanish and Parshall fields in the fourth quarter and in December 2011:

Operated and Non-operated Net Production for Sanish and Parshall Fields (In BOE)
	4^th Qtr 2011			December 2011
	Parshall	Sanish	Total	Parshall	Sanish	Total
Whiting Operated	18,401	1,904,524	1,922,925	5,330	718,824	724,154
Non-Operated	262,051	198,053	460,104	82,711	79,097	161,808
	280,452	2,102,577	2,383,029	88,041	797,921	885,962
Daily BOE	3,050	22,850	25,900	2,840	25,740	28,580 ^(1)

⁽¹⁾ Up from 27,215 BOE/d in September 2011.

Robinson Lake Gas Plant. As of February 1, 2012, the plant was processing 52.7 MMcf of gas per day (gross). Currently, there is inlet compression in place to process 60 MMcf per day. Compression can be added to 90 MMcf per day as the processing demand increases. Whiting owns a 50% interest in the plant.

Belfield Gas Processing Plant. Construction of our Belfield gas plant was completed on schedule, and the plant began processing gas on December 20, 2011 at a rate of 5.0 MMcf per day. Currently, there is inlet compression in place to process 24 MMcf per day.

Belfield Oil Pipeline. Whiting completed the installation of its seven mile oil transmission line to the Bridger Pipeline interconnect in late January 2012. Whiting’s oil production began flowing into the pipeline on February 1, 2012. We estimate that the completion of this pipeline will reduce transportation costs by $3.50 – $4.00 per barrel.

EOR Projects

North Ward Estes Field. Production from our North Ward Estes field averaged 8,795 BOE per day in the fourth quarter of 2011. This average rate represented a 4% increase from the 8,440 net daily rate in the third quarter of 2011. Since September 1, 2011, we have been receiving our full contract quantities of 134 MMcf of CO₂ per day at North Ward Estes. Whiting is currently injecting approximately 300 MMcf of CO₂ per day into the field, of which about 64% is recycled gas.

Residual Oil Zone. Whiting recently began drilling operations at a pilot project in North Ward Estes field to test a Residual Oil Zone (“ROZ”). Current EOR production from North Ward Estes is from the Yates formation at a depth of approximately 2,600 feet. We plan to initiate CO₂ injection into the deeper ROZ by the end of the first quarter 2012. Resource potential from the ROZ has been independently estimated as 148 MMBOE based on well tests conducted to date. This is not currently reflected in our “Resource Potential” table as we await results from our initial pilot, which are expected by year-end 2012.

Postle Field. In the fourth quarter of 2011, the Postle field produced at an average net rate of 8,050 BOE per day, which is about flat with the 7,980 BOE average daily rate in the third quarter of 2011. Whiting is currently injecting 120 MMcf of CO₂ per day into the field, of which approximately 71% is recycled gas.

Other Development Areas

Delaware Basin: Big Tex Prospect. Whiting’s lease position at Big Tex consists of 1 120,719 gross (89,820 net) acres. Targets include the Brushy Canyon, Bone Spring, and Wolfcamp horizons. Based on positive results from the Trainer Trust 16-2 vertical Bone Spring well and the Bissett 9701H horizontal Bone Spring well, we have planned a 13-well drilling program for Big Tex in 2012 with a budget of $57 million. The majority of these wells are expected to be horizontal Bone Spring wells. On the western half of our acreage, we are also initiating a vertical Wolfbone program. These wells will commingle production from the Wolfcamp and from as many as three benches in the Bone Spring. Whiting expects to continue to operate two rigs on the prospect in 2012.

Denver Basin: Redtail Niobrara Prospect. The Redtail prospect targets the Niobrara “B” zone in the Denver Basin, in Weld County, Colorado. Whiting controls 105,597 gross (73,611 net) acres in the play. Whiting recently completed its first well drilled on a 960-acre spacing unit, the Horsetail 18-0733H, with an initial production rate of 718 BOE per day from a 6,296-foot lateral. The Horsetail well was drilled about 12 miles northeast of the Wildhorse discovery well. Utilizing recently acquired 3D seismic, we plan to drill eight wells at Redtail in 2012. These include a three-well development program located between our Wildhorse discovery well and our Horsetail 18-0733H. Our Horsetail well was drilled to total depth in 16 days. Whiting expects to continue to operate one drilling rig on the prospect in 2012.

Operated Drilling and Workover Rig Count

As of December 31, 2011, 27 operated drilling rigs and 67 operated workover rigs were active on our properties. We were also participating in the drilling of two non-operated wells, all in North Dakota.

The breakdown of our operated rigs as of December 31, 2011 was as follows:

Region	Drilling	Workover
Northern Rockies	21	23
Permian Basin	4	7
EOR Projects
Postle	1	6
North Ward Estes	1	30
Michigan	--	1
Totals	27	67

As of February 1, 2012 we had 33 service units active in the Williston Basin. These service units have reduced the number of shut-in wells at the Sanish field from 66 to 31 as of February 1, 2012. We expect to reduce the number of shut-in wells awaiting service work in Sanish field to approximately 20 by the end of the first quarter.

Other Financial and Operating Results

The following table summarizes the Company’s net production and commodity price realizations for the quarters ended December 31, 2011 and 2010:

	Three Months Ended
Production	12/31/11			12/31/10			Change
Oil and NGLs (MMBbls)		5.45			5.03		8%
Natural gas (Bcf)		6.35			7.32		(13%)
Total equivalent (MMBOE)		6.50			6.25		4%
Average Sales Price
Oil and NGLs (per Bbl):
Price received	$	84.86		$	74.53		14%
Effect of crude oil hedging ^(1)		(0.77	)		(1.80	)
Realized price	$	84.09		$	72.73		16%
Natural gas (per Mcf):
Price received	$	4.72		$	4.34		9%
Effect of natural gas hedging ^(1)		0.05			0.05
Realized price	$	4.77		$	4.39		9%

⁽¹⁾ Whiting realized pre-tax cash settlement losses of $4.2 million on its crude oil hedges and gains of $0.4 million on its natural gas hedges during the fourth quarter of 2011. A summary of Whiting’s outstanding hedges is included later in this news release.

Fourth Quarter and Full-Year 2011 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,
	2011			2010			2011		2010
Production (MMBOE)		6.50			6.25			24.78		23.60
Sales price, net of hedging	$	75.07		$	63.66		$	73.88	$	61.48
Lease operating expense		12.69			11.33			12.33		11.37
Production tax		5.96			4.25			5.62		4.40
General & administrative		3.46			2.59			3.43		2.74
Exploration		1.45			1.12			1.85		1.39
Cash interest expense		2.20			1.78			2.17		2.05
Cash income tax expense (benefit)		(0.11	)		(0.24	)		0.16		0.21
	$	49.42		$	42.83		$	48.32	$	39.32

During the fourth quarter of 2011, the company-wide basis differential for crude oil compared to NYMEX was $9.16 per barrel, which compared to $8.85 per barrel in the third quarter of 2011. We expect our company-wide oil price differential to average between $13.00 and $14.00 during the first quarter of 2012. Within the Bakken, Whiting’s operated production had a differential of approximately $14.00 per barrel in February 2012.

The company-wide basis differential for natural gas compared to NYMEX in the fourth quarter of 2011 was at a premium of $1.18 per Mcf, which compared to a premium of $0.80 per Mcf in the third quarter of 2011. We expect our natural gas to sell at a premium price of between $0.60 and $0.90 during the first quarter of 2012.

Fourth Quarter and Full-Year 2011 Drilling and Expenditures Summary

The table below summarizes Whiting’s operated and non-operated drilling activity and exploration and development costs incurred for the three and twelve months ended December 31, 2011:

	Gross/Net Wells Completed
					Capital
			Total New	% Success	Costs
	Producing	Non-Producing	Drilling	Rate	(in MM)
Q4 11	76 / 38.8	1 / 0.3 ^(1)	77 / 39.1	99% / 99%	$	523.5 ^(2)
12M 11	278 / 130.5	6 / 4.5 ^(1)	284 / 135.0	98% / 97%	$	1,840.2 ^(2)

^(1)	Includes one exploratory dry hole and one development dry hole for shallow Wilcox at Greenbranch field in McMullen Co., TX, one re-entry mechanical failure exploratory well at the Big Tex prospect, Pecos Co., TX, one exploratory Niobrara dry hole in Carbon Co., WY, one non-op development Red River oil test in Richland Co., MT, and one non-op development test in Kent Co., TX.
^(2)	Includes $7.2 million and $186.9 million of acreage acquisition costs for the three and twelve months ended December 31, 2011, respectively.

Outlook for First Quarter and Full-Year 2012

As mentioned earlier in this news release, we have increased our production guidance for the first quarter and full-year 2012. This production guidance does not consider the impact of the announced offering of Whiting USA Trust II, which is projected to produce approximately 1,467 MBOE for the full-year 2012 based on the trust’s projected 90% ownership of the underlying properties. We have also adjusted our costs per BOE and have increased our company-wide differential due to the recent widening of Bakken differentials in the Williston Basin.

The following table provides guidance for the first quarter and full-year 2012 based on current forecasts, including Whiting’s full-year 2012 capital budget of $1,600 million:

	Guidance
	First Quarter		Full-Year
	2012		2012
Production (MMBOE)		6.80 - 7.20		28.30 - 29.70
Lease operating expense per BOE	$	12.80 - $ 13.10	$	13.00 - $ 13.40
General and admin. expense per BOE	$	3.60 - $ 3.80	$	3.70 - $ 3.90
Interest expense per BOE	$	2.55 - $ 2.75	$	2.50 - $ 2.70
Depr., depletion and amort. per BOE	$	20.00 - $ 20.50	$	20.50 - $ 20.90
Prod. taxes (% of production revenue)		7.8% - 8.0%		7.9% - 8.2%
Oil price differentials to NYMEX per Bbl		($ 13.00) - ($ 14.00)		($ 10.50) - ($ 11.50)
Gas price premium to NYMEX per Mcf ^(1)	$	0.60 - $ 0.90	$	0.60 - $ 0.90

⁽¹⁾ 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 January 31, 2012:

		Weighted Average	As a Percentage of
Hedge	Contracted Volume	NYMEX Price Collar Range	December 2011
Period	(Bbls per Month)	(per Bbl)	Oil Production
2012
Q1	984,054	$66.63 - $108.56	51.2%
Q2	983,850	$66.63 - $108.56	51.2%
Q3	983,650	$66.63 - $108.55	51.1%
Q4	983,477	$66.63 - $108.55	51.1%
2013
Q1	290,000	$47.67 - $90.21	15.1%
Q2	290,000	$47.67 - $90.21	15.1%
Q3	290,000	$47.67 - $90.21	15.1%
Oct	290,000	$47.67 - $90.21	15.1%
Nov	190,000	$47.22 - $85.06	9.9%

The following summarizes Whiting Petroleum Corporation’s natural gas hedges as of January 31, 2012:

		Weighted Average	As a Percentage of
Hedge	Contracted Volume	NYMEX Price Collar Range	December 2011
Period	(MMBtu per Month)	(per MMBtu)	Gas Production
2012
Q1	33,381	$7.00 - $15.55	1.6%
Q2	32,477	$6.00 - $13.60	1.6%
Q3	31,502	$6.00 - $14.45	1.5%
Q4	30,640	$7.00 - $13.40	1.5%

Whiting also had the following fixed-price natural gas contracts in place as of January 31, 2012:

		Weighted Average	As a Percentage of
Hedge	Contracted Volume	Contracted Price	December 2011
Period	(MMBtu per Month)	(per MMBtu)	Gas Production
2012
Q1	576,963	$5.30	27.7%
Q2	461,296	$5.41	22.1%
Q3	465,630	$5.41	22.4%
Q4	398,667	$5.46	19.1%
2013
Q1	360,000	$5.47	17.3%
Q2	364,000	$5.47	17.5%
Q3	368,000	$5.47	17.7%
Q4	368,000	$5.47	17.7%
2014
Q1	330,000	$5.49	15.8%
Q2	333,667	$5.49	16.0%
Q3	337,333	$5.49	16.2%
Q4	337,333	$5.49	16.2%

Selected Operating and Financial Statistics
	Three Months Ended December 31,						Twelve Months Ended December 31,
	2011			2010			2011			2010
Selected operating statistics
Production
Oil and NGLs, MBbl		5,445			5,026			20,373			19,030
Natural gas, MMcf		6,347			7,323			26,443			27,392
Oil equivalents, MBOE		6,503			6,246			24,780			23,596
Average Prices
Oil per Bbl (excludes hedging)	$	84.86		$	74.53		$	84.92		$	70.53
Natural gas per Mcf (excludes hedging)	$	4.72		$	4.34		$	4.92		$	4.86
Per BOE Data
Sales price (including hedging)	$	75.07		$	63.66		$	73.88		$	61.48
Lease operating	$	12.69		$	11.33		$	12.33		$	11.37
Production taxes	$	5.96		$	4.25		$	5.62		$	4.40
Depreciation, depletion and amortization	$	19.58		$	16.66		$	18.89		$	16.69
General and administrative	$	3.46		$	2.59		$	3.43		$	2.74
Selected Financial Data
(In thousands, except per share data)
Total revenues and other income	$	498,637		$	413,469		$	1,899,622		$	1,516,099
Total costs and expenses	$	400,434		$	308,429		$	1,119,303		$	974,656
Net income available to common shareholders	$	62,620		$	65,925		$	490,610		$	272,683
Earnings per common share, basic ^(1)	$	0.54		$	0.56		$	4.18		$	2.57
Earnings per common share, diluted ^(1)	$	0.53		$	0.56		$	4.14		$	2.55
Average shares outstanding, basic ^(1)		117,381			117,098			117,345			106,338
Average shares outstanding, diluted ^(1)		118,644			118,564			118,668			107,846
Net cash provided by operating activities	$	328,329		$	277,022		$	1,192,083		$	997,289
Net cash used in investing activities	$	(493,156	)	$	(346,496	)	$	(1,760,036	)	$	(914,574	)
Net cash provided by (used in) financing    activities	$	174,550		$	85,215		$	564,812		$	(75,723	)

⁽¹⁾ All share and per share amounts have been retroactively restated for the 2010 periods to reflect the Company’s two-for-one stock split in February 2011.

Conference Call

The Company’s management will host a conference call with investors, analysts and other interested parties on Thursday, February 23, 2012 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 2011 financial and operating results. Please call [phone] (U.S./Canada) or [phone] (International) and enter the pass code 77936886 to be connected to the call. Access to a live Internet broadcast will be available at 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 23, 2012.

A telephonic replay will be available beginning approximately two hours after the call on Thursday, February 23, 2012 and continuing through Thursday, March 1, 2012. You may access this replay at [phone] (U.S./Canada) or [phone] (International) and entering the pass code 36375988. 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 acquires, exploits, develops and explores for 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 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 or natural gas prices; our level of success in exploitation, exploration, development and production activities; adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures, including our ability to obtain CO₂; 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; impacts of the global recession and tight credit markets; our ability to obtain external capital to finance exploration and development operations and acquisitions; federal and state regulatory 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; 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; 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, 2011. 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 resources are estimated volumes associated with undiscovered accumulations. These represent quantities of petroleum which are estimated to be potentially recoverable from oil and gas deposits identified on the basis of indirect evidence but which have not yet been drilled. This class represents a higher risk than contingent resources since the risk of discovery is also added. For prospective resources to become classified as contingent resources, hydrocarbons must be discovered, the accumulations must be further evaluated and an estimate of quantities that would be recoverable under appropriate development projects prepared. Estimates of resources are by nature more uncertain than reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company.

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, 2011, to be filed with the Securities and Exchange Commission.

WHITING PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS (Unaudited) (In thousands)
	December 31, 2011			December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents	$	15,811		$	18,952
Accounts receivable trade, net		262,515			199,713
Prepaid expenses and other		20,377			14,878
Total current assets		298,703			233,543
Property and equipment:
Oil and gas properties, successful efforts method:
Proved properties		7,221,550			5,661,619
Unproved properties		354,774			226,336
Other property and equipment		150,933			98,092
Total property and equipment		7,727,257			5,986,047
Less accumulated depreciation, depletion and    amortization		(2,088,517	)		(1,630,824	)
Total property and equipment, net		5,638,740			4,355,223
Debt issuance costs		33,306			34,226
Other long term assets		74,860			25,785
TOTAL ASSETS	$	6,045,609		$	4,648,777

WHITING PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS (Unaudited) (In thousands, except share and per share data)
	December 31, 2011		December 31, 2010
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable trade	$	56,673	$	35,016
Accrued capital expenditures		142,827		84,789
Accrued liabilities and other		157,214		153,062
Revenues and royalties payable		103,894		82,124
Taxes payable		31,195		30,291
Derivative liabilities		73,647		69,375
Deferred income taxes		1,584		4,548
Total current liabilities		567,034		459,205
Long-term debt		1,380,000		800,000
Deferred income taxes		823,643		539,071
Derivative liabilities		47,763		95,256
Production Participation Plan liability		80,659		81,524
Asset retirement obligations		61,984		76,994
Deferred gain on sale		29,619		41,460
Other long-term liabilities		25,776		23,952
Total liabilities		3,016,478		2,117,462
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, 2011 and 172,500 issued and   outstanding as of December 31, 2010, aggregate   liquidation preference of $17,239,100 at December   31, 2011		-		-
Common stock, $0.001 par value, 300,000,000 shares   authorized; 118,105,279 issued and 117,380,884   outstanding as of December 31, 2011, 117,967,876   issued and 117,098,506 outstanding as of December   31, 2010 ^(1)		118		59
Additional paid-in capital		1,554,223		1,549,822
Accumulated other comprehensive income		240		5,768
Retained earnings		1,466,276		975,666
Total Whiting shareholders’ equity		3,020,857		2,531,315
Noncontrolling interest		8,274		-
Total equity		3,029,131		2,531,315
TOTAL LIABILITIES AND EQUITY	$	6,045,609	$	4,648,777

⁽¹⁾ All common share amounts (except par value and par value per share amounts) have been retroactively restated as of December 31, 2010 to reflect the Company’s two-for-one stock split in February 2011.

WHITING PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (In thousands, except per share data)
	Three Months Ended December 31,						Twelve Months Ended December 31,
	2011			2010			2011			2010
REVENUES AND OTHER INCOME:
Oil and natural gas sales	$	492,025		$	406,327		$	1,860,146		$	1,475,288
Gain on hedging activities		1,432			3,558			8,758			23,198
Amortization of deferred gain on sale		3,482			4,000			13,937			15,613
Gain (loss) on sale of properties		1,581			(530	)		16,313			1,388
Interest income and other		117			114			468			612
Total revenues and other income		498,637			413,469			1,899,622			1,516,099
COSTS AND EXPENSES:
Lease operating		82,550			70,762			305,487			268,348
Production taxes		38,778			26,539			139,190			103,880
Depreciation, depletion and amortization		127,335			104,061			468,203			393,897
Exploration and impairment		23,318			21,456			84,644			59,371
General and administrative		22,515			16,178			84,985			64,694
Interest expense		16,649			13,175			62,516			59,078
Loss on early extinguishment of debt		-			-			-			6,235
Change in Production Participation Plan   liability		(3,925	)		2,541			(865	)		12,091
Commodity derivative (gain) loss, net		93,214			53,717			(24,857	)		7,062
Total costs and expenses		400,434			308,429			1,119,303			974,656
INCOME BEFORE INCOME TAXES		98,203			105,040			780,319			541,443
INCOME TAX EXPENSE (BENEFIT):
Current		(737	)		(1,489	)		3,853			4,979
Deferred		36,110			40,335			284,838			199,811
Total income tax expense (benefit)		35,373			38,846			288,691			204,790
NET INCOME		62,830			66,194			491,628			336,653
Net loss attributable to noncontrolling interest		59			-			59			-
NET INCOME AVAILABLE TO SHAREHOLDERS		62,889			66,194			491,687			336,653
Preferred stock dividends and inducement premium		(269	)		(269	)		(1,077	)		(63,970	)
NET INCOME AVAILABLE TO COMMON    SHAREHOLDERS	$	62,620		$	65,925		$	490,610		$	272,683
EARNINGS PER COMMON SHARE ^(1):
Basic	$	0.54		$	0.56		$	4.18		$	2.57
Diluted	$	0.53		$	0.56		$	4.14		$	2.55
WEIGHTED AVERAGE SHARES OUTSTANDING ^(1):
Basic		117,381			117,098			117,345			106,338
Diluted		118,644			118,564			118,668			107,846

⁽¹⁾ All share and per share amounts have been retroactively restated for the 2010 periods to reflect the Company’s two-for-one stock split in February 2011.

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,
	2011			2010			2011			2010
Net Income Available to Common Shareholders	$	62,620		$	65,925		$	490,610		$	272,683
Cash Premium on Induced Conversion		-			-			-			47,529
Adjustments Net of Tax:
Amortization of Deferred Gain on Sale		(2,227	)		(2,521	)		(8,781	)		(9,708	)
(Gain) Loss on Sale of Properties		(1,012	)		334			(10,278	)		(863	)
Impairment Expense		8,869			9,119			24,435			16,492
Loss on Early Extinguishment of Debt		-			-			-			3,877
Unrealized Derivative (Gains) Losses		56,273			26,137			(39,751	)		(25,329	)
Adjusted Net Income ^(1)	$	124,523		$	98,994		$	456,235		$	304,681
Adjusted Net Income Available to Common    Shareholders per Share, Basic ^(2)	$	1.06		$	0.85		$	3.89		$	2.99
Adjusted Net Income Available to Common    Shareholders per Share, Diluted ^(2)	$	1.05		$	0.84		$	3.85		$	2.71

⁽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 US GAAP and may not be comparable to other similarly titled measures of other companies.

⁽²⁾ All per share amounts have been retroactively restated for the 2010 periods to reflect the Company’s two-for-one stock split in February 2011.

WHITING PETROLEUM CORPORATION Reconciliation of Net Cash Provided by Operating Activities to Discretionary Cash Flow (In thousands)
	Three Months Ended
	December 31,
	2011			2010
Net cash provided by operating activities	$	328,329		$	277,022
Exploration		9,455			6,985
Exploratory dry hole costs		(210	)		(1,023	)
Changes in working capital		(8,496	)		(5,555	)
Preferred stock dividends paid		(269	)		(269	)
Discretionary cash flow ^(1)	$	328,809		$	277,160
	Twelve Months Ended
	December 31,
	2011			2010
Net cash provided by operating activities	$	1,192,083		$	997,289
Exploration		45,861			32,846
Exploratory dry hole costs		(4,924	)		(3,819	)
Changes in working capital		10,762			(60,545	)
Preferred stock dividends paid		(1,077	)		(16,441	)
Discretionary cash flow ^(1)	$	1,242,705		$	949,330

⁽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, loss on early extinguishment of debt, 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, not including the preferred stock inducement premium. 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 US GAAP and may not be comparable to other similarly titled measures of other companies.

WHITING PETROLEUM CORPORATION Finding Cost and Reserve Replacement Schedule 12/31/11 ^(1) (In thousands)
				Three Years
				2009-2011
	2009	2010	2011	Total/Avg.
Proved Acquisition	$78,800	$22,763	$4,324	$105,887
Unproved Acquisition	$12,872	$155,472	$191,482	$359,826
Development Cost	$436,721	$723,687	$1,245,150	$2,405,558
Exploration Cost	$50,970	$114,012	$400,823	$565,805
Total	$579,363	$1,015,934	$1,841,779	$3,437,076
Acquisition Reserves
Acquisition Res. – Oil (MBbl)	3,177	505	172	3,854
Acquisition Res. – Gas (MMcf)	4,155	1,526	1,639	7,320
Total – Aqu. Res. – MBOE	3,870	759	445	5,074
Development Reserves
Development Res. – Oil (MBbl)	25,115	29,434	44,684	99,233
Development Res. – Gas (MMcf)	41,969	23,135	23,211	88,315
Total – Dev. Res. – MBOE	32,109	33,290	48,553	113,952
Revisions
Reserve Revisions – Oil (MBbl)	33,566	19,799	20,203	73,568
Reserve Revisions – Gas (MMcf)	-62,618	-618	-7,217	-70,453
Total - Reserve Rev. – MBOE	23,130	19,695	19,000	61,825
Cost Per BOE to Acquire	$20.36	$29.98	$9.71	$20.87
Cost Per BOE to Develop	$9.06	$18.74	$27.20	$18.95
All-in Finding Cost per BOE	$9.80	$18.90	$27.09	$19.01
FUTURE DEVELOPMENT COSTS
Proved Undeveloped CapEx ^(1)				$1,982,813
Proved Undeveloped Reserves - MBOE ^(1)				106,949
				$18.54
Probable and Possible CapEx ^(1)				$4,265,947
Probable and Possible Reserves – MBOE ^(1)				301,235
All-In Rate with Future Development Cost and Prob. and Poss. ^(1)				$14.16
RESERVE REPLACEMENT
Acquisition Reserves	3,870	759	445	5,074
Development Reserves	32,109	33,290	48,553	113,952
Reserve Revisions	23,130	19,695	19,000	61,825
Total New Reserves – MBOE	59,109	53,744	67,998	180,851
Production (MBOE)	20,269	23,596	24,780	68,645
Reserve Replacement %	292%	228%	274%	263%

⁽¹⁾ See “Disclosure Regarding Reserves and Resources” earlier in this news release.