8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of

the Securities Exchange Act of 1934

_______________________

Date of Report
(Date of earliest
event reported):	February 24, 2010

                         Whiting Petroleum Corporation                         

(Exact name of registrant as specified in its charter)

Delaware	1-31899	20-0098515
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

            1700 Broadway, Suite 2300, Denver, Colorado 80290-2300           

(Address of principal executive offices, including ZIP code)

                              (303) 837-1661                              

(Registrant’s telephone number, including area code)

_______________________

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

£	Written communications pursuant to Rule 425 under the Securities Act (17 C.F.R. §230.425)
£	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 C.F.R. §240.14a-12)
£	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 C.F.R. §240.14d-2(b))
£	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 C.F.R. §240.13e-4(c))

Item 2.02.                      Results of Operations and Financial Condition.

On February 24, 2010, Whiting Petroleum Corporation issued a press release announcing its financial and operating results for the fourth quarter and year ended December 31, 2009 and providing certain guidance for the first quarter of 2010 and full year 2010.  A copy of such press release is furnished as Exhibit 99 and is incorporated by reference herein.

Item 9.01.                      Financial Statements and Exhibits.

(a) Financial Statements of Businesses Acquired.  Not applicable.

(b) Pro Forma Financial Information.  Not applicable.

(c) Shell Company Transactions.  Not applicable.

(d) Exhibits:

(99) Press Release of Whiting Petroleum Corporation, dated February 24, 2010.

- 2 - -

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

		WHITING PETROLEUM CORPORATION
Date: February 24, 2010	By:	/s/ James J. Volker
		James J. Volker
		Chairman, President and Chief Executive Officer

- 3 - -

WHITING PETROLEUM CORPORATION

FORM 8-K

EXHIBIT INDEX

Exhibit Number	Description
(99)	Press Release of Whiting Petroleum Corporation, dated February 24, 2010.

- 4 -

EX-99

Company contact:	John B. Kelso, Director of Investor Relations
	303.837.1661 or john.kelso@whiting.com

Whiting Petroleum Corporation Announces Fourth Quarter and Full-Year 2009 Financial and Operating Results

Company Increases Proved Reserves 15% to

275 MMBOE at Year-End 2009

2009 Production Up 16% Over 2008 to a Record 20.27 MMBOE

Replaces 292% of 2009 Production at an

All-In F & D Cost of $16.97 per BOE

Q4 09 Discretionary Cash Flow of $185.5 Million

2010 E & D Budget of $830 Million for 210-Well Drilling Program

DENVER – February 24, 2010 – Whiting Petroleum Corporation’s (NYSE: WLL) production in the fourth quarter of 2009 totaled a record 5.22 million barrels of oil equivalent (MMBOE), of which 4.09 million barrels were crude oil/natural gas liquids (78%) and 1.13 MMBOE was natural gas (22%).  This fourth quarter 2009 production total equates to a new record daily average production rate of 56,710 barrels of oil equivalent (BOE), compared to the 55,540 BOE per day average rate in the fourth quarter of 2008.  Compared to the third quarter of 2009, production rose 2%.

Production in 2009 totaled a record 20.27 MMBOE, or 55,530 BOE per day, compared to production of 17.52 MMBOE, or 47,860 BOE per day, in 2008.  The 16% increase in production for 2009 versus 2008 was primarily the result of organic production growth in the North Dakota Bakken and continued response from Whiting’s two CO2 enhanced oil recovery (EOR) projects.

Financial Results

Discretionary cash flow in the fourth quarter of 2009 totaled $185.5 million, compared to the $111.0 million reported for the same period in 2008.  The increase in discretionary cash flow in the fourth quarter of 2009 versus the comparable 2008 period was primarily the result of a 30% increase in the Company’s realized oil price (net of hedging), including the price of natural gas liquids (NGLs).  For the year ended December 31, 2009, Whiting’s discretionary cash flow totaled $513.0 million, compared to $744.4 million in 2008.  A reconciliation of discretionary cash flow to net cash provided by operating activities is on page 26 of this news release.

In the fourth quarter of 2009, Whiting reported a loss of $11.2 million, or $0.24 per basic and diluted share, on total revenues of $316.0 million.  This compares to a fourth quarter 2008 loss of $3.0 million, or $0.07 per basic and diluted share, on total revenues of $223.9 million.  Whiting’s fourth quarter 2009 net loss includes after-tax, non-cash losses on hedging arrangements of $45.7 million, or $0.90 per share.

For the year ended December 31, 2009, Whiting reported a net loss of $117.2 million, or $2.36 per basic and diluted share, on total revenues of $979.4 million.  This compares to net income of $252.1 million, or $5.96 per basic share and $5.94 per diluted share, on total revenues of $1.2 billion in 2008.  Whiting’s full-year 2009 net loss includes after-tax, non-cash losses on hedging arrangements of $137.5 million, or $2.75 per share.

Proved Reserves at December 31, 2009

As of December 31, 2009, Whiting had estimated proved reserves of 275.0 MMBOE, of which 64% were classified as proved developed.  These estimated proved reserves had a pre-tax PV10% value of approximately $2,875.7 million, of which approximately 96% came from properties located in Whiting’s Permian Basin, Rocky Mountains and Mid-Continent core areas.  The following table summarizes Whiting’s estimated proved reserves as of December 31, 2009 by core area, the corresponding pre-tax PV10% value and the December 2009 average daily production rate:

2

	Proved Reserves (1)
Core Area	Oil (MMBbl)(2)		Natural  Gas (Bcf)		Total (MMBOE)		%  Oil(2)			Pre-Tax PV10%Value(3) (In MM)		December 2009 Average Daily Production  (MBOE/d)
Permian Basin		112.3		66.2		123.3		91	%	$	901.3		11.7
Rocky Mountains		70.2		159.4		96.8		73	%		1,266.3		30.3
Mid-Continent		36.6		15.2		39.1		94	%		581.3		9.3
Gulf Coast		2.3		36.6		8.4		27	%		69.6		3.0
Michigan		2.4		30.0		7.4		32	%		57.2		2.3
Total		223.8		307.4		275.0		81	%	$	2,875.7		56.6

(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 most recent 12 months, pursuant to current SEC and FASB guidelines.  The NYMEX prices used were $61.18/Bbl and $3.87/Mcf.

(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 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, 2009, our discounted future income taxes were $532.2 million and our standardized measure of discounted future net cash flows was $2,343.5 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.

3

The following is a summary of Whiting’s changes in quantities of proved oil and gas reserves for the year ended December 31, 2009:

	Oil (MBbl)			Natural Gas (MMcf)			Total (MBOE)
Balance – December 31, 2008		180,008			354,779			239,138
Extensions and discoveries		25,115			41,969			32,109
Sales of minerals in place		(2,689	)		(1,559	)		(2,949	)
Purchases of minerals in place		3,177			4,155			3,870
Production		(15,381	)		(29,333	)		(20,269	)
Revisions to previous estimates		33,566			(62,618	)		23,130	(1)
Balance – December 31, 2009		223,796			307,393			275,029

 (1) Of the 23.1 MMBOE of upward revisions, 17.3 MMBOE were due to commodity prices and 5.8 MMBOE were the result of well performance and new data.  Of the 62.6 Bcf of downward gas revisions, 17.6 Bcf was attributable to the lower gas price assumption used in the year-end 2009 reserve estimate.  The remaining 45.0 Bcf included 13.0 Bcf of performance related adjustments on producing wells and 10.0 Bcf of adjustments on proved undeveloped reserve assignments in the Sulphur Creek field.  In connection with the Company’s adoption of the new SEC rules on oil and gas reserve estimation, there was also a downward revision of 11.0 Bcf related to the removal of proved undeveloped locations from the Company’s drilling plans.  The remaining 11.0 Bcf of downward revisions was spread across numerous wells throughout all regions.

Most of the proved reserve additions at December 31, 2009 came from the Company’s Bakken play in the Sanish and Parshall fields in Mountrail County, North Dakota.  An estimated 25.0 MMBOE of new Bakken proved reserves were booked at year-end 2009, bringing Whiting’s total proved reserves in the two fields to 42.3 MMBOE at year-end 2009.  Of this 42.3 MMBOE, 56% were proved, developed and producing, 44% were proved undeveloped, 85% were attributed to the Sanish field and 15% to Whiting’s interests in the Parshall field.  As of December 31, 2009, the finding cost for the Sanish and Parshall fields is $13.61 per proved BOE.  This includes Whiting’s interest in the Robinson Lake Gas Plant and the Company’s oil and gas gathering systems in the area.  The Company’s net production from the Sanish and Parshall fields in 2009 totaled approximately 6.0 MMBOE, or an average of 16,520 BOE per day.

Approximately 5.8 MMBOE of reserve additions at December 31, 2009 were attributable to performance-related upward revisions, primarily from the North Ward Estes CO2 project.

In total, Whiting replaced 292% of its 2009 production of 20.3 MMBOE with 59.1 MMBOE of proved reserve additions.  Through drilling alone, the Company replaced 158% of its 2009 production with 32.1 MMBOE of proved reserve additions.  The table on page 27 of this news release summarizes Whiting’s all-in finding and development costs and reserve replacement for the five-year period ended December 31, 2009.

4

James J. Volker, Whiting’s Chairman, President and CEO, commented, “This is an exciting time for Whiting Petroleum and our shareholders.  In 2009, we generated 32.1 MMBOE of reserve additions through the drillbit, replacing 158% of our record 2009 production of 20.3 MMBOE.  We expect our organic growth to continue in 2010 and beyond.  We have a 210-well drilling program planned for 2010 and estimate that we could have as many as 2,400 gross wells in our current drilling inventory.  This includes 1,400 wells in our independently engineered reserve base, which consists of proved, probable and possible reserves, and 1,000 potential wells in our total resource base.”

Mr. Volker continued, “We grew through the acquisition of producing properties in 2004 and 2005 to increase production levels and provide upside potential through further development.  We are now more focused on organic drilling activity and on the development of previously acquired properties.  We believe the combination of acquisitions, subsequent development and organic drilling provides us a broad set of growth alternatives as we direct our resources to the properties we believe represent the best use of our capital investments.  We are now generating substantially all of our production growth organically.  We delivered our results during 2009 by focusing on our Bakken drilling program and our two EOR projects.  In 2010, one of our primary objectives is to establish another resource play.  We believe our Lewis & Clark prospect area, where we have amassed a 202,000 net acre position, has the potential to be such a play.  With these key projects, we are optimistic about Whiting’s operational results in 2010 and beyond.”

5

2010 Exploration and Development Budget

Our current 2010 capital budget for exploration and development expenditures is $830.0 million, which we expect to fund with net cash provided by our operating activities.  To the extent net cash provided by operating activities is higher or lower than currently anticipated, we would adjust our capital budget accordingly or use a portion of our available capacity under our bank credit agreement.  Our 2010 capital budget currently is allocated among our major development areas as indicated in the chart below:

	2010 Planned Capital Expenditures		Planned Wells
	(In millions)		Gross		Net
Northern Rockies
Sanish Field	$	274		86		48
Parshall Field	$	11		12		2
Lewis & Clark Area	$	62		13		9
Other Northern Rockies	$	30		22		7
Subtotal	$	377		133		66
CO2 Projects
North Ward Estes(1)	$	169		--		--
Postle (1)	$	88		24		23
Subtotal	$	257		24		23
Permian Basin
Various	$	51		20		16
Central Rockies
Flat Rock Field	$	20		4		4
Sulphur Creek Field	$	14		5		5
Other Central Rockies	$	15		6		4
Subtotal	$	49		15		13
Gulf Coast
Various	$	30		13		8
Michigan
PDC Expl. & Dvlp.	$	16		5		4
Other, Non-Operated	$	20		--		--
Exploration Expense (2)	$	30		--		--
Grand Total	$	830		210		130

(1) 2010 planned capital expenditures at our CO2 projects include $51.6 million for purchased CO2 at North Ward Estes and $12.1 million for Postle CO2 purchases.

(2) Comprised primarily of exploration salaries, lease delay rentals and seismic and other development.

6

Operations Update

Core Development Areas

Bakken and Three Forks Development Increases Production

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 2009:

Operated and Non-operated Net Production for Sanish and Parshall Fields (In BOE)
	4th Qtr 2009						December 2009
	Parshall		Sanish		Total		Parshall		Sanish		Total
Whiting Operated		53,442		1,001,980		1,055,422		18,038		357,184		375,222
Non-Operated		560,431		97,830		658,261		181,272		32,235		213,507
		613,873		1,099,810		1,713,683		199,310		389,419		588,729
Daily BOE		6,675		11,955		18,625		6,430		12,560		18,990	(1)

(1) Includes approximately 685 net BOE per day of NGLs and natural gas from plant operations.

Whiting’s net production from the Middle Bakken formation in the Sanish and Parshall fields of Mountrail County, North Dakota averaged 18,990 BOE per day in December 2009, up 9% from the 17,410 BOE average daily rate in September 2009 and up 34% from the 14,165 BOE average daily rate in December 2008.

Sanish Field.  In 2009, Whiting completed 38 operated wells in the Sanish field, bringing to 68 the number of Whiting-operated wells in the field as of December 31, 2009.  Including non-operated wells, there were 107 producing wells in the Sanish field at year-end 2009.  In 2010, Whiting intends to drill 86 operated wells (48 net wells) in the field, of which 76 are planned Bakken wells and 10 are planned Three Forks wells.  From January 1 through February 15, 2010, an additional six Whiting-operated wells were completed.  One of these wells was completed in the Three Forks formation at an initial production rate of 1,262 BOE per day while the remaining five were completed in the Bakken formation with average initial production rates of 2,802 BOE per day.  As of February 15, 2010, 70 Whiting-operated wells were producing from the Bakken and four wells were producing from the Three Forks in the Sanish field.  In addition, nine operated wells were being drilled and eight operated wells were being completed.  The 74 Whiting-operated wells at Sanish had average initial production rates of 2,093 BOE per day.  Sixty-nine wells produced at an average rate of 858 BOE per day during their first 30 days of production, while 68 wells produced at an average rate of 713 BOE per day during their first 60 days of production and 60 wells produced at an average rate of 658 BOE per day during their first 90 days of production.  An estimated 170 Bakken wells and 139 Three Forks wells remain to be drilled in the field.  The Company holds interests in a total of 118,026 gross acres (69,636 net acres) in the Sanish field.

7

Whiting’s net production from the Sanish field in the fourth quarter of 2009 averaged 11,955 BOE per day, an increase of 14% over the third quarter 2009 average rate of 10,470 BOE per day.  Our net production from the Sanish field averaged 12,560 BOE per day in December 2009, a 19% increase from 10,565 BOE per day in September 2009 and a 68% increase from 7,495 BOE per day in December 2008.  The Company recently added three drilling rigs in the Sanish field, bringing to nine the total number of Whiting-operated rigs in the field.

Whiting has reduced its completed well cost for Bakken wells in the Sanish field.  The reduction in costs has primarily been the result of our “Drill Wells On Paper” (DWOP) program that applies the best practices and best logistical planning of all our drilling and completion contractors to produce drilling and completion efficiencies.  This has reduced the average time from spud date to rig release to below 30 days from 60 days earlier in our drilling program.  The completed well cost for our most recent wells in the Sanish field were approximately $5 million per well, down from $8 million to $10 million per well when the development project was initiated.

Whiting completed the installation of its 17-mile oil line connecting the Sanish field to the Enbridge pipeline in Stanley, North Dakota.  This 8-inch diameter line has a daily capacity of approximately 65,000 barrels of oil per day.  The pipeline came on stream in late December 2009 and is currently moving approximately 10,000 barrels of oil per day.  Whiting expects to have all of its net operated oil production in the pipeline upon completion of Enbridge’s tank facility at Stanley.  This is expected to occur in June 2010.  In January 2010, Enbridge Inc. increased its take-away capacity to 161,000 barrels per day from 110,000 barrels per day and has ongoing construction to further expand its take-away capacity.  Enbridge expects to add 30,000 barrels per day in the first quarter of 2011 and 85,000 barrels per day in the second quarter of 2013 for a total of 276,000 barrels per day of take-away capacity.

Whiting’s Robinson Lake gas plant is currently processing 21 MMcf per day.  Capacity will be expanded to 35 MMcf per day in June 2010.  Whiting owns a 50% interest in the plant.  The plant receives 25% of the net proceeds from natural gas and NGL sales.  As of February 15, 2010, sales from the plant were 16.6 MMcf of gas and 3,146 barrels of NGLs per day, from which Whiting was netting 2.1 MMcf of gas and 393 barrels of NGLs per day from its plant ownership.  There are currently 69 Whiting-operated wells and 60 third-party wells connected to the gas gathering system.

8

Parshall Field. Immediately east of the Sanish field is the Parshall field, where we own interests in 74,863 gross acres (18,412 net acres).  The Company’s net production from its interests in the Parshall field during the fourth quarter of 2009 averaged 6,675 BOE per day, a 2% decrease from the 6,830 BOE per day average in the third quarter of 2009.  Our net production from the Parshall field averaged 6,430 BOE per day in December 2009, a 6% decrease from 6,845 BOE per day in September 2009 and a 4% decrease from the 6,725 BOE average daily rate in December 2008.  As of February 15, 2010, we have participated in 114 wells at Parshall, of which 111 are producing and three are awaiting completion.  Exploration and development in the Parshall field is currently focused on the Three Forks formation.

Increasing Production from EOR Projects

Postle Field. Production continues to increase from our Postle field, which produces from the Morrow sandstone, in Texas County, Oklahoma.  In the fourth quarter of 2009, the field produced at an average net rate of 8,910 BOE per day, representing a 33% increase from the 6,720 BOE net daily rate in the fourth quarter of 2008.  In December 2009, the field produced at an average net rate of 9,200 BOE per day, Postle’s highest production rate in more than 33 years.  The December 2009 average daily rate represents a 2% sequential increase over the net 9,000 BOE per day rate in September 2009.  Four of the five units in the Postle field are currently active CO2 EOR projects.  The fifth unit produces from the Cherokee formation and is being evaluated for waterflood reactivation.  CO2 injection into the fifth unit is not currently planned.  As of February 15, 2010, there was one drilling rig and three workover rigs active in the field.

In 2009, our Midland/Postle team was presented with a 2008 Excellence Award from the Oil and Gas Investor  for “Best Field Rejuvenation” at the Postle field.  Net production from the field has more than doubled since Whiting acquired it in August 2005, from 4,200 BOE per day to 9,200 BOE per day in December 2009.

North Ward Estes Field.  Based on further evaluations of the reservoir quality at North Ward Estes field, Whiting has elected to expand the scope of its CO2 project in the field to include eight phases, up from four phases previously.  Whiting now plans CO2 injection in virtually the entire field, including the Northern Waterflood area and the Southeast Waterflood area.  In addition, Whiting has increased its planned CO2 injection volume for the field.  These decisions contributed to a 59% increase in the field’s probable and possible reserves, to 124 MMBOE at year-end 2009 from 78 MMBOE at year-end 2008.  Reserve estimates for the field were independently engineered.

9

Production continues to ramp up at our North Ward Estes field, which is located in Ward and Winkler Counties, Texas.  Production from the field increased 6% to a net 6,955 BOE per day in the fourth quarter of 2009 from a net 6,590 BOE per day in the fourth quarter of 2008.  The field’s production averaged 7,110 BOE in December 2009, a 7% sequential increase over the 6,635 BOE per day net rate in September 2009.  Whiting initiated CO2 injection in Phase I in May 2007 and in Phase II in March 2009.  In this field, Whiting is developing new and reactivated wells for water and CO2 injection and production purposes.  Whiting plans to install oil, gas and water processing facilities in a total of eight phases.  We estimate that Phase III-A will be substantially complete in the fourth quarter of 2010.  As of February 15, 2010, there were 25 workover rigs active in the field.

In two separate transactions during the fourth quarter of 2009, Whiting acquired additional royalty and overriding royalty interests in the North Ward Estes field for a total of $66.1 million.  In aggregate, Whiting estimates that the net production attributable to the two acquisitions is 500 BOE per day and the proved reserves attributable to the acquired interests is 3.8 MMBOE.  In addition, Whiting estimates the probable and possible reserves attributable to the acquired interests is 2.8 MMBOE.  (Please refer to page 21 of this news release for more information on “probable and possible” reserves.)  The two acquisitions increased the Company’s average net revenue interest in the North Ward Estes field to approximately 82.8% from 80%.  Reserves attributable to royalty and overriding royalty interests are not burdened by operating expenses or any additional capital costs, including CO2 costs, which are paid by the working interest owners.  Whiting estimates that the non-cost bearing nature of these interests makes them worth approximately 33% more than working interest barrels.

Flat Rock Field. Whiting holds 22,029 gross acres (11,454 net acres) in the Flat Rock field, located in the Uinta Basin in Uintah County, Utah.  Whiting moved a drilling rig to Flat Rock field in early September 2009 after signing a fixed-price gas contract for the field’s production.  The contract covers daily volumes of 10 MMcf of gas from September 1, 2009 through December 31, 2014 at a wellhead price of $5.50 per Mcf.  Effective January 1, 2010 through December 2011, an additional 5 MMcf of daily gas volumes are under contract at a fixed-price of $5.38 per Mcf at the wellhead.  Whiting expects to complete an additional four Entrada wells in the Flat Rock field in 2010.

Highlighting recent operations at the Flat Rock field was the completion of the Company’s Ute Tribal 11-30-14-20 well.  This vertical well was completed in the Dakota formation with an initial production rate of 6.8 MMcf of gas per day on February 12, 2010.  Whiting holds a 100% working interest and an 85% net revenue interest in the well.

10

Sulphur Creek Field.Whiting executed a similar fixed-price gas contract for production from its Boies Ranch prospect in Rio Blanco County, Colorado.  The contract, which was effective November 1, 2009, covers daily volumes of 5 MMcf through December 31, 2010, 4 MMcf in 2011, 3 MMcf in 2012, 2 MMcf in 2013, and 1 MMcf in 2014 at a fixed price of $5.34 at the wellhead.  A consolidated schedule of our fixed-price gas contracts can be found on page 18 of this news release.

Whiting holds 10,196 gross acres (4,455 net acres) in the Sulphur Creek field, which is comprised of the Boies Ranch and Jimmy Gulch prospects.  As of February 15, 2010, 35 wells which were completed in the Mesa Verde formation were producing at a net rate of 6.0 MMcf of gas per day.  At the Boies Ranch prospect, the Company owns the surface and mineral rights, which improves the Company’s rate of return on each well drilled on the prospect.  At Boies Ranch, Whiting estimates that it has 228 remaining drilling locations, which includes potential locations in the probable, possible and resource categories.  Downspacing in certain parts of Boies Ranch could generate 243 additional locations, bringing the total number of potential locations to 471.  At Jimmy Gulch, we estimate that we have 29 remaining drilling locations, including probable and possible locations.  Downspacing in Jimmy Gulch could generate 32 additional locations, bringing the total number of potential locations at Jimmy Gulch to 61.  In aggregate, we estimate that we may have as many as 532 potential locations at Boies Ranch and Jimmy Gulch.

New Prospect Drilling Areas

Lewis & Clark Prospect Area. As of December 31, 2009, Whiting held 213,496 gross acres (127,761 net acres) in the Lewis & Clark area, located in Golden Valley and Billings Counties, North Dakota.  The Company has assembled an additional 106,475 gross acres (74,606 net acres) in the area, primarily in Stark County, North Dakota, bringing Whiting’s total acreage position in the Lewis & Clark area to 319,971 gross acres (202,367 net acres).  Whiting estimates that it has as many as 500 potential well locations on this acreage, targeting the Three Forks formation.

On November 25, 2009, Whiting completed the Federal 32-4HBKCE flowing 1,835 barrels of oil and 811 Mcf of gas per day, or 1,970 BOE per day, during a 24-hour test of the Three Forks formation at a vertical depth of 10,530 feet.  The well was fracture stimulated in 15 stages, all using sliding sleeve technology.  Whiting holds a working interest of 84% and a net revenue interest of 71% in the Federal well.

11

The Federal well was drilled on the southwest side of the Lewis & Clark prospect.  Whiting moved a drilling rig to the Lewis & Clark prospect in February 2010 and anticipates drilling at least 13 Three Forks wells on the prospect during 2010.

Operated Drilling and Workover Rig Count

As of February 15, 2010, 12 operated drilling rigs and 39 operated workover rigs were active on our properties.  We were also participating in the drilling of two non-operated wells, one on the Gulf Coast and the other in the Sanish field.  The breakdown of our operated rigs is as follows:

Region	Drilling		Workover
Northern Rockies
Sanish Field		9		3
Lewis & Clark		1		1
Central Rockies
Flat Rock Field		1		2
CO2 Projects
Postle		1		3
North Ward Estes		0		25
Permian		0		3
Mid-Continent/Michigan		0		2
Totals		12		39

We expect our operated drilling rig count to average approximately 15 and our operated workover rig count to average between 40 and 45 in 2010.

Other 2009 Notable Events

Commercial Banking Facility. In October 2009, Whiting’s bank syndicate reaffirmed our borrowing base at $1.1 billion.  At December 31, 2009, we had $160 million drawn on, and $0.3 million in letters of credit outstanding under, the facility, yielding availability of $939.7 million.  Our debt to total capitalization ratio was 25.6% at December 31, 2009.  Given the reduction in bank debt and continued increase in cash flows, we were well within all financial covenants under our bank credit agreement and bond indentures at December 31, 2009.

12

Sanish Field Transaction.On June 4, 2009, Whiting announced an agreement with a privately held independent oil company covering twenty-five 1,280-acre units and one 640-acre unit located primarily in the western portion of the Sanish field in Mountrail County, North Dakota.  The private company agreed to pay 65% of Whiting’s net working interest completed well cost to receive 50% of Whiting’s working interest and net revenue interest in the first and second wells planned for each of the units.  Pursuant to the agreement, Whiting will remain the operator for each unit.  At the closing of the transaction on June 4, 2009, the private company paid Whiting $107.3 million, representing $6.4 million for acreage costs, $65.8 million for 65% of Whiting’s cost in the 18 wells drilled or drilling as of June 4, 2009 and $35.1 million for a 50% interest in Whiting’s Robinson Lake gas plant and oil and gas gathering system.

As a result of the 65% for 50% cost sharing arrangement under the transaction, Whiting’s finding and development cost of all producing wells drilled under the agreement will improve by 30%.  As of February 15, 2010, 28 wells under this agreement had been drilled and completed.  The remaining 23 wells are expected to be completed by year-end 2010.

Other Financial and Operating Results

The following table summarizes the Company’s net production and commodity price realizations for the quarters ended December 31, 2009 and 2008:

	Three Months Ended
Production	12/31/09			12/31/08		Change
Oil and condensate (MMBbls)		4.09			3.77		8%
Natural gas (Bcf)		6.76			8.03		(16%)
Total equivalent (MMBOE)		5.22			5.11		2%
Average Sales Price
Oil and condensate (per Bbl):
Price received	$	65.52		$	47.37		38%
Effect of crude oil hedging (1)		(1.80	)		1.65
Realized price	$	63.72		$	49.02		30%
Natural gas (per Mcf):
Price received	$	4.88		$	4.38		11%
Effect of natural gas hedging (1)		0.05			0.01
Realized price	$	4.93		$	4.39		12%

(1) Whiting realized pre-tax cash settlement losses on its crude oil and natural gas hedges of $7.0 million during the fourth quarter of 2009.  A summary of Whiting’s outstanding hedges is included later in this news release.

13

Fourth Quarter and Full-Year 2009 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,
	2009		2008		2009		2008
Production (MMBOE)		5.22		5.11		20.27		17.52
Sales price, net of hedging	$	56.35	$	43.08	$	45.01	$	69.06
Lease operating expense		11.49		12.41		11.71		13.77
Production tax		4.11		3.05		3.19		5.00
General & administrative		2.26		1.91		2.09		3.52
Exploration		4.23		1.52		2.31		1.67
Cash interest expense		2.44		2.90		2.64		3.37
Cash income tax expense		0.25		0.20		0.01		0.13
	$	31.57	$	21.09	$	23.06	$	41.60

During the fourth quarter, the company-wide basis differential for crude oil compared to NYMEX was $10.65 per barrel, which compared to $9.43 per barrel in the third quarter of 2009.  We expect our oil price differential to average between $8.50 and $9.50 in the first quarter of 2010.  Within the Bakken, Whiting-operated production has a current differential of approximately $7.00 per barrel.

Our company-wide natural gas price compared to NYMEX in the fourth quarter was at a premium of $0.72 per Mcf, which compared to a discount of $0.05 per Mcf in the third quarter of 2009.  We expect our natural gas to sell at a premium price of between $0.00 and $0.30 during the first quarter of 2010.

Fourth Quarter 2009 Drilling Summary

The table below summarizes Whiting’s operated and non-operated drilling activity and exploration and development costs incurred for the three and 12 months ended December 31, 2009:

	Gross/Net Wells Completed				Expl. & Dev.
			Total New	% Success	Cost
	Producing	Non-Producing	Drilling	Rate	(in millions)
Q409	27 / 9.3	7 / 5.1	34 / 14.4	79% / 65%	$ 115.4
12M09	138 / 51.1	7 / 5.1	145 / 56.2	95% / 91%	$ 479.8

14

During the fourth quarter, the following three wells were charged to exploration expense on Whiting’s income statement as exploratory dry holes:

· Beckman Canyon 21-24D located on the Hatfield prospect in Carbon County, Wyoming – Whiting operated this well that tested the Tensleep formation and the Phosphoria formation and found both zones to be wet.  The company tested oil in the Niobrara formation off the flank of the Espy structure and demonstrated the presence of a continuous phase oil reservoir off structure.  In 2010, Whiting has planned two follow-up wells to test the fractured Niobrara down dip. The first well will be logged and cored and depending on that evaluation a horizontal leg may be drilled.  The initial well cost $5.0MM (Whiting’s WI 100%).

·   Artus 19-33 located on the Hatfield prospect in Carbon County Wyoming - Whiting operated this well that tested the Niobrara formation horizontally and found the fractures to be cemented.  The initial well cost $4.4 million (Whiting’s WI 100%).

·   Three Mile 43-18H located on the Hatch Point prospect in San Juan County, Utah - Whiting operated this well that tested the Cane Creek formation horizontally and found it to be productive with initial pump test rates of 30-50 barrels of oil per day.  Those rates were not considered commercial.  The company is working on a frac technique to access more of this reservoir.  The initial well cost $8.8 million net (Whiting’s WI 53.4%).

Outlook for First Quarter and Full-Year 2010

The following table provides guidance for the first quarter and full-year 2010 based on current forecasts, including Whiting’s full-year 2010 capital budget of $830.0 million (excluding any potential acquisition costs).

	Guidance
	First Quarter	Full-Year
	2010	2010
Production (MMBOE)	5.10 - 5.30	22.20 - 22.60
Lease operating expense per BOE	$ 11.30 - $ 11.60	$ 10.80 - $ 11.00
General and admin. expense per BOE	$   2.40 - $   2.60	$   2.40 - $   2.60
Interest expense per BOE	$   2.90 - $   3.10	$   2.80 - $   3.00
Depr., depletion and amort. per BOE	$ 18.30 - $ 18.70	$ 19.10 - $ 19.40
Prod. Taxes (% of production revenue)	7.3% - 7.7%	7.5% - 7.9%
Oil price differentials to NYMEX per Bbl	$   8.50 - $   9.50	$   8.50 - $   9.00
Gas price premiumto NYMEX per Mcf (1)	$   0.00 - $   0.30	$   0.00 -  $   0.30

(1) Includes the effect of Whiting’s fixed-price gas contracts.  Please refer to page 19 of this news release.

15

Oil Hedges

The following summarizes Whiting’s crude oil hedges as of February 16, 2010:

		Weighted Average	As a Percentage of
Hedge	Contracted Volume	NYMEX Price Collar Range	December 2009
Period	(Bbls per Month)	(per Bbl)	Oil Production
2010
Q1	565,910	$62.06 - $80.45	40.9%
Q2	650,643	$64.55 - $85.31	47.0%
Q3	640,398	$62.59 - $84.92	46.3%
Q4	625,146	$62.64 - $86.99	45.2%
2011
Q1	369,917	$56.73 - $85.28	26.7%
Q2	369,696	$56.72 - $85.26	26.7%
Q3	369,479	$56.71 - $85.22	26.7%
Q4	369,255	$56.69 - $85.21	26.7%
2012
Q1	339,054	$56.39 - $86.95	24.5%
Q2	338,850	$56.38 - $86.93	24.5%
Q3	338,650	$56.37 - $86.89	24.5%
Q4	338,477	$56.36 - $86.88	24.5%
2013
Q1	290,000	$55.34 - $85.94	21.0%
Q2	290,000	$55.34 - $85.94	21.0%
Q3	290,000	$55.34 - $85.94	21.0%
Oct	290,000	$55.34 - $85.94	21.0%
Nov	190,000	$54.59 - $81.75	13.7%

16

The following summarizes Whiting Petroleum Corporation’s natural gas hedges as of February 16, 2010:

		Weighted Average	As a Percentage of
Hedge	Contracted Volume	NYMEX Price Collar Range	December 2009
Period	(MMBtu per Month)	(per MMBtu)	Gas Production
2010
Q1	43,295	$7.00 - $18.65	2.0%
Q2	41,835	$6.00 - $13.20	1.9%
Q3	40,555	$6.00 - $14.00	1.8%
Q4	39,445	$7.00 - $14.20	1.8%
2011
Q1	38,139	$7.00 - $17.40	1.7%
Q2	36,954	$6.00 - $13.05	1.7%
Q3	35,855	$6.00 - $13.65	1.6%
Q4	34,554	$7.00 - $14.25	1.6%
2012
Q1	33,381	$7.00 - $15.55	1.5%
Q2	32,477	$6.00 - $13.60	1.5%
Q3	31,502	$6.00 - $14.45	1.4%
Q4	30,640	$7.00 – $13.40	1.4%

17

Whiting also has the following fixed-price natural gas contracts in place as of February 16, 2010:

		Weighted Average	As a Percentage of
Hedge	Contracted Volume	NYMEX Price	December 2009
Period	(MMBtu per Month)	(per MMBtu)	Gas Production
2010
Q1	689,000	$5.36	31.0%
Q2	695,667	$5.36	31.3%
Q3	702,333	$5.36	31.6%
Q4	702,333	$5.36	31.6%
2011
Q1	659,000	$5.39	29.7%
Q2	665,333	$5.38	30.0%
Q3	649,667	$5.38	29.3%
Q4	649,667	$5.38	29.3%
2012
Q1	457,000	$5.41	20.6%
Q2	461,333	$5.41	20.8%
Q3	465,667	$5.41	21.0%
Q4	398,667	$5.46	18.0%
2013
Q1	360,000	$5.47	16.2%
Q2	364,000	$5.47	16.4%
Q3	368,000	$5.47	16.6%
Q4	368,000	$5.47	16.6%
2014
Q1	330,000	$5.49	14.9%
Q2	333,667	$5.49	15.0%
Q3	337,333	$5.49	15.2%
Q4	337,333	$5.49	15.2%

18

Selected Operating and Financial Statistics

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2009			2008			2009			2008
Selected operating statistics
Production
Oil and condensate, MBbl		4,091			3,772			15,381			12,448
Natural gas, MMcf		6,759			8,025			29,333			30,419
Oil equivalents, MBOE		5,218			5,109			20,269			17,517
Average Prices
Oil, Bbl (excludes hedging)	$	65.52		$	47.37		$	52.51		$	86.99
Natural gas, Mcf (excludes hedging)	$	4.88		$	4.38		$	3.75		$	7.68
Per BOE Data
Sales price (including hedging)	$	56.35		$	43.08		$	45.01		$	69.06
Lease operating	$	11.49		$	12.41		$	11.71		$	13.77
Production taxes	$	4.11		$	3.05		$	3.19		$	5.00
Depreciation, depletion and amortization	$	17.86		$	19.16		$	19.48		$	15.84
General and administrative	$	2.26		$	1.91		$	2.09		$	3.52
Selected Financial Data
(In thousands, except per share data)
Total revenues and other income	$	316,035		$	223,860		$	979,360		$	1,222,119
Total costs and expenses	$	325,972		$	218,633		$	1,142,195		$	813,299
Net income (loss) available to common shareholders	$	(11,206	)	$	(3,037	)	$	(117,184	)	$	252,143
Earnings (loss) per common share, basic	$	(0.24	)	$	(0.07	)	$	(2.36	)	$	5.96
Earnings (loss) per common share, diluted	$	(0.24	)	$	(0.07	)	$	(2.36	)	$	5.94
Average shares outstanding, basic		50,845			42,323			50,044			42,310
Average shares outstanding, diluted		50,845			42,323			50,044			42,447
Net cash provided by operating activities	$	147,795		$	151,577		$	435,612		$	763,029
Net cash used in investing activities	$	(152,941	)	$	(279,361	)	$	(505,335	)	$	(1,134,947	)
Net cash provided by financing activities	$	1,246		$	116,764		$	72,059		$	366,764

Conference Call

The Company’s management will host a conference call with investors, analysts and other interested parties on Thursday, February 25, 2010 at 11:00 a.m. EDT (10:00 a.m. CDT, 9:00 a.m. MDT) to discuss Whiting’s fourth quarter and full-year 2009 financial and operating results.  Please call (866) 804-6921 (U.S./Canada) or (857) 350-1667 (International) and enter the pass code 39760790 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. (EDT) on February 25, 2010.

19

A telephonic replay will be available beginning approximately two hours after the call on Thursday, February 25, 2010 and continuing through Thursday, March 4, 2010.  You may access this replay at (888) 286-8010 (U.S./Canada) or (617) 801-6888 (International) and entering the pass code 30401718.  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 Permian Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the United States.  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 report, 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.

20

These risks and uncertainties include, but are not limited to:  declines in oil or natural gas prices; impacts of the global recession and tight credit markets; 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; our ability to obtain external capital to finance exploration and development operations and acquisitions; 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 the Company’s Annual Report on Form 10-K.  We assume no obligation, and disclaim any duty, to update the forward-looking statements in the Company’s Annual Report on Form 10-K.

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.

21

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.

22

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, 2009, to be filed with the Securities and Exchange Commission.

WHITING PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands)

	December 31, 2009			December 31, 2008
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	11,960		$	9,624
Accounts receivable trade, net		152,082			123,386
Derivative assets		4,723			46,780
Prepaid expenses and other		7,260			37,284
Total current assets		176,025			217,074
PROPERTY AND EQUIPMENT:
Oil and gas properties, successful efforts method:
Proved properties		4,870,688			4,423,197
Unproved properties		100,706			106,436
Other property and equipment		100,833			91,099
Total property and equipment		5,072,227			4,620,732
Less accumulated depreciation, depletion and amortization		(1,274,121	)		(886,065	)
Total property and equipment, net		3,798,106			3,734,667
DEBT ISSUANCE COSTS		24,672			10,779
DERIVATIVE ASSETS		8,473			38,104
OTHER LONG-TERM ASSETS		22,266			28,457
TOTAL	$	4,029,542		$	4,029,081

23

WHITING PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share data)

	December 31, 2009		December 31, 2008
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	14,023	$	64,610
Accrued capital expenditures		29,998		84,960
Accrued liabilities		62,891		45,359
Accrued interest		10,501		9,673
Oil and gas sales payable		46,327		35,106
Accrued employee compensation and benefits		22,105		41,911
Production taxes payable		21,188		20,038
Deferred gain on sale		12,966		14,650
Derivative liabilities		49,551		17,354
Deferred income taxes		11,325		15,395
Tax sharing liability		1,857		2,112
Total current liabilities		282,732		351,168
NON-CURRENT LIABILITIES:
Long-term debt		779,585		1,239,751
Deferred income taxes		341,037		390,902
Derivative liabilities		137,621		28,131
Production Participation Plan liability		69,433		66,166
Asset retirement obligations		66,846		47,892
Deferred gain on sale		58,462		73,216
Tax sharing liability		20,744		21,575
Other long-term liabilities		2,997		1,489
Total non-current liabilities		1,476,725		1,869,122
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY:
Preferred stock, $0.001 par value, 5,000,000 shares authorized;
6.25% convertible perpetual preferred stock, 3,450,000 and 0 shares issued and outstanding as of December 31, 2009 and December 31, 2008, respectively, aggregate liquidation preference of $345,000,000		3		-
Common stock, $0.001 par value, 75,000,000 shares authorized;
51,363,638 issued and 50,845,374 outstanding as of December 31, 2009, 42,582,100 issued and 42,323,336 outstanding as of December 31, 2008		51		43
Additional paid-in capital		1,546,635		971,310
Accumulated other comprehensive income		20,413		17,271
Retained earnings		702,983		820,167
Total stockholders’ equity		2,270,085		1,808,791
TOTAL	$	4,029,542	$	4,029,081

24

WHITING PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(In thousands, except per share data)

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2009			2008			2009			2008
REVENUES AND OTHER INCOME:
Oil and natural gas sales	$	300,989		$	213,821		$	917,541		$	1,316,480
Gain (loss) on hedging activities		10,703			5,347			38,776			(107,555	)
Amortization of deferred gain on sale		4,001			4,466			16,596			12,143
Gain on sale of properties		238			-			5,947			-
Interest income and other		104			226			500			1,051
Total revenues and other income		316,035			223,860			979,360			1,222,119
COSTS AND EXPENSES:
Lease operating		59,927			63,382			237,270			241,248
Production taxes		21,447			15,560			64,672			87,548
Depreciation, depletion and amortization		93,170			97,893			394,792			277,448
Exploration and impairment		33,486			24,691			73,014			55,257
General and administrative		11,781			9,781			42,357			61,684
Interest expense		15,588			16,318			64,608			65,078
Change in Production Participation Plan liability		265			5,160			3,267			32,124
Commodity derivative (gain) loss, net		90,308			(14,152	)		262,215			(7,088	)
Total costs and expenses		325,972			218,633			1,142,195			813,299
INCOME (LOSS) BEFORE INCOME TAXES		(9,937	)		5,227			(162,835	)		408,820
INCOME TAX EXPENSE (BENEFIT):
Current		1,282			1,008			236			2,361
Deferred		(5,404	)		7,256			(56,189	)		154,316
Total income tax expense (benefit)		(4,122	)		8,264			(55,953	)		156,677
NET INCOME (LOSS)		(5,815	)		(3,037	)		(106,882	)		252,143
Preferred stock dividends		(5,391	)		-			(10,302	)		-
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS	$	(11,206	)	$	(3,037	)	$	(117,184	)	$	252,143
EARNINGS (LOSS) PER COMMON SHARE, BASIC	$	(0.24	)	$	(0.07	)	$	(2.36	)	$	5.96
EARNINGS (LOSS) PER COMMON SHARE, DILUTED	$	(0.24	)	$	(0.07	)	$	(2.36	)	$	5.94
WEIGHTED AVERAGE SHARES OUTSTANDING, BASIC		50,845			42,323			50,044			42,310
WEIGHTED AVERAGE SHARES OUTSTANDING, DILUTED		50,845			42,323			50,044			42,447

25

WHITING PETROLEUM CORPORATION

Reconciliation of Net Cash Provided by Operating Activities to Discretionary Cash Flow

(In thousands)

	Three Months Ended
	December 31,
	2009			2008
Net cash provided by operating activities	$	147,795		$	151,577
Exploration		22,090			7,752
Changes in working capital		20,978			(48,346	)
Preferred stock dividends paid		(5,391	)		-
Discretionary cash flow (1)	$	185,472		$	110,983

	Twelve Months Ended
	December 31,
	2009			2008
Net cash provided by operating activities	$	435,612		$	763,029
Exploration		46,875			29,302
Changes in working capital		40,858			(47,955	)
Preferred stock dividends paid		(10,302	)		-
Discretionary cash flow (1)	$	513,043		$	744,376

(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, gain/loss on mark-to-market derivatives, preferred stock dividends paid and other non-current items less the gain on sale of properties and amortization of deferred gain on sale.  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 GAAP and may not be comparable to other similarly titled measures of other companies.

26

Whiting Petroleum Corp. Finding Cost and Reserve Replacement Schedule 12/31/09 (1) (in thousands)
																	Five Years
																	2005-2009
	2005			2006				2007			2008			2009			Total/Avg.
Proved Acquisition	$	906,208		$	29,778			$	8,128		$	294,056		$	78,800		$	1,316,970
Unproved Acquisition	$	16,124		$	38,628			$	13,598		$	98,841		$	12,872		$	180,063
Development Cost	$	215,162		$	408,828			$	506,057		$	914,616		$	436,721		$	2,481,384
Exploration Cost	$	22,532		$	81,877			$	56,741		$	42,621		$	50,970		$	254,741
Change in Future Development Cost	$	692,229		$	267,685			$	10,048		$	(204,633	)	$	423,541		$	1,188,870
Total	$	1,852,255		$	826,796			$	594,572		$	1,145,501		$	1,002,904		$	5,422,028
Acquisition Reserves
Acquisition Res. – Oil (MBbl)		115,737			670				691			513			3,177			120,788
Acquisition Res. – Gas (MMcf)		101,082			4,009			-				90,329			4,155			199,575
Total – Aqu. Res. – MBOE		132,584			1,338				691			15,568			3,870			154,051
Development Reserves
Development Res. – Oil (MBbl)		1,956			4,125				10,973			20,395			25,115			62,564
Development Res. – Gas (MMcf)		21,068			19,362				40,936			57,093			41,969			180,428
Total – Dev. Res. – MBOE		5,467			7,352				17,796			29,911			32,109			92,634
Revisions
Reserve Revisions – Oil (MBbl)		950			2,053				392			(20,851	)		33,566			16,110
Reserve Revisions – Gas (MMcf)		(45,322	)		(57,780	)			8,079			(74,689	)		(62,618	)		(232,330	)
Total – Reserve Rev. – MBOE		(6,604	)		(7,577	)			1,739			(33,299	)		23,130			( 22,612	)
Cost Per BOE to Acquire	$	6.83		$	22.25			$	11.76		$	18.89		$	20.36		$	8.55
Cost per BOE to Develop	$	-		$	-			$	30.02		$	-		$	16.73	(2)(3)(4)	$	58.63
All-in finding cost per BOE	$	14.09		$	742.74			$	29.40		$	94.05		$	16.97		$	24.20
							Unrisked Probable and Possible Reserves – BOE (1)											286,596
							Probable and Possible Cap – Ex (1)										$	2,244,649
							All-In Rate (1)										$	15.01
RESERVE REPLACEMENT
Acquisition Reserves		132,584			1,338				691			15,568			3,870			154,051
Development Reserves		5,467			7,352				17,796			29,911			32,109			92,635
Reserve Revisions		(6,604	)		(7,577	)			1,739			(33,299	)		23,130			(22,612	)
Total New Reserves – MBOE		131,447			1,113				20,226			12,180			59,109			224,074
Production (MBOE)		12,077			15,157				14,706			17,517			20,269			79,726
Reserve Replacement %		1088	%		7	%			138	%		70	%		292	%		281	%

(1) See “Disclosure Regarding Reserves and Resources” on page 22 for disclosures relating to reserves.

(2) Finding and Development (F&D) cost excluding acquisitions is equal to $1,002,904M total – $78,800M for acquisitions = $924,104M / 32,109 MBOE development reserves + 23,130 MBOE reserve revisions = $16.73/BOE.

(3) F&D cost for non-proved reserves is equal to $704,075M ($924,104M – $150,029M for EOR – $70,000M for 39 PUD locations = $704,075M) / 55,239 MBOE = $12.75/BOE.

(4) F&D cost for non-proved reserves without price effects is $704,075M / 55,239 MBOE – 17,258 MBOE (see Footnote #1 on page 4) = $18.54/BOE.

 27