UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Whiting Petroleum Corporation

(Exact name of registrant as specified in its charter)

Delaware		20-0098515
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1700 Broadway, Suite 2300
Denver, Colorado		80290-2300
(Address of principal executive offices)		(Zip code)

Registrant’s telephone number, including area code: (303) 837-1661

Securities registered pursuant to Section 12(b) of the Act:

Common Stock, $.001 par value Preferred Share Purchase Rights (Title of Class)		New York Stock Exchange New York Stock Exchange (Name of each exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Act. Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). (Check one):

Large accelerated filer þ                    Accelerated filer o                    Non-accelerated filer o

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

Aggregate market value of the voting common stock held by non-affiliates of the registrant at June 30, 2006: $1,540,817,968.

Number of shares of the registrant’s common stock outstanding at February 15, 2007: 36,947,681 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2007 Annual Meeting of Stockholders are incorporated by reference into Part III.

 

 

TABLE OF CONTENTS

Certain Definitions					3
		PART I			5
Item 1.		Business			5
Item 1A.		Risk Factors			15
Item 1B.		Unresolved Staff Comments			25
Item 2.		Properties			25
Item 3.		Legal Proceedings			31
Item 4.		Submission of Matters to a Vote of Security Holders			31
Executive Officers of the Registrant					32
		PART II			34
Item 5.		Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			34
Item 6.		Selected Financial Data			36
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			38
Item 7A.		Quantitative and Qualitative Disclosure About Market Risk			56
Item 8.		Financial Statements and Supplementary Data			59
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			98
Item 9A.		Controls and Procedures			98
Item 9B.		Other Information			98
		PART III			100
Item 10.		Directors, Executive Officers and Corporate Governance			100
Item 11.		Executive Compensation			100
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			100
Item 13.		Certain Relationships, Related Transactions and Director Independence			101
Item 14.		Principal Accounting Fees and Services			101
		PART IV			101
Item 15.		Exhibits, Financial Statement Schedules			101
2003 Equity Incentive Plan, as amended
First Amendment to Production Participation Plan
Production Participation Plan Credit Service Agreement
Production Participation Plan Supplemental Payment Agreement
Statement Regarding Computation of Ratios of Earnings to Fixed Charges
Subsidiaries
Consent of Deloitte & Touche LLP
Consent of Cawley, Gillespie & Associates, Inc.
Consent of R. A. Lenser & Associates, Inc.
Consent of Ryder Scott Company, L.P.
Certification by Chairman, President and CEO Pursuant to Section 302
Certification by the Vice President and CFO Pursuant to Section 302
Certification of the Chairman, President and CEO Pursuant to Section 1350
Certification of the Vice President and CFO Pursuant to Section 1350

CERTAIN DEFINITIONS

     Unless the context otherwise requires, the terms “we,” “us,” “our” or “ours” when used in this Annual Report on Form 10-K refer to Whiting Petroleum Corporation, together with its operating subsidiaries. When the context requires, we refer to these entities separately.

     We have included below the definitions for certain crude oil and natural gas terms used in this Annual Report on Form 10-K:

     “3-D seismic” Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

     “Bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil and other liquid hydrocarbons.

     “Bcf” One billion cubic feet of natural gas.

     “BOE” One stock tank barrel equivalent of oil, calculated by converting natural gas volumes to equivalent oil barrels at a ratio of six Mcf to one Bbl of oil.

     “BOE/d” One BOE per day.

     “Bopd” Barrels of oil or other liquid hydrocarbons per day.

     “completion” The installation of permanent equipment for the production of crude oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

     “MBOE” One thousand BOE.

     “MBOE/d” One thousand BOE per day.

     “Mcf” One thousand cubic feet of natural gas.

     “Mcf/d” One Mcf per day.

     “MMbbl” One million barrels of oil or other liquid hydrocarbons.

     “MMBOE” One million BOE.

     “MMbtu” One million British Thermal Units.

     “MMcf” One million cubic feet of natural gas.

     “NGLs” Natural gas liquids.

     “PDNP” Proved developed nonproducing.

     “PDP” Proved developed producing.

     “plugging and abandonment” Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.

     “PUD” Proved undeveloped.

     “pre-tax PV10%” The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with Securities and Exchange Commission (“SEC”) guidelines, net of estimated lease operating expense, production taxes and future development costs, using price and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or Federal income taxes and discounted using an annual discount rate of 10%. Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC. See footnote (1) to the Proved Reserves table in Item 1. “Business” for more information.

     “reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

     “working interest” The interest in an crude oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to share in production, subject to all royalties, overriding royalties and other burdens and to share in all costs of exploration, development and operations and all risks in connection therewith.

Item 1. Business

     We are an independent oil and gas company engaged in acquisition, development, exploitation, production and exploration activities primarily in the Permian Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the United States. We were incorporated in 2003 in connection with our initial public offering.

     Since our inception in 1980, we have built a strong asset base and achieved steady growth through property acquisitions, development and exploration activities. As of December 31, 2006, our estimated proved reserves totaled 248.1 MMBOE, representing a 6% decrease in our proved reserves since December 31, 2005. Our estimated December 2006 average daily production was 40.5 MBOE/d, which remained consistent with December 2005 average daily production and implied an average reserve life of approximately 16.8 years.

     The following table summarizes our estimated proved reserves by core area, the corresponding pre-tax PV10% value, our standardized measure of discounted future net cash flows as of December 31, 2006, and our December 2006 average daily production:

																						December 2006
		Proved Reserves																				Average Daily
		Oil				Natural				Total				%				Pre-Tax PV10%				Production
Core Area		(MMbbl)				Gas (Bcf)				(MMBOE)				Oil				Value(1)				(MBOE/d)
																		(In millions)
Permian Basin			103.1				78.3				116.1				89	%		$	1,345.3				12.6
Rocky Mountains			37.1				96.9				53.2				70	%		$	816.4				12.6
Mid-Continent			47.4				36.4				53.5				88	%		$	771.8				5.2
Gulf Coast			2.2				62.2				12.6				18	%		$	211.6				6.4
Michigan			5.2				45.1				12.7				41	%		$	207.1				3.7
Total			195.0				318.9				248.1				79	%		$	3,352.2				40.5
Discounted Future Income Taxes			—				—				—				—				(960.0	)			—
Standardized Measure of Discounted Future Net Cash Flows			—				—				—				—			$	2,392.2				—

     We expect to continue to build on our successful acquisition track record and seek property acquisitions that complement our existing core properties. Additionally, we believe that our significant drilling inventory, combined with our operating experience and cost structure, provides us with significant organic growth opportunities. During 2006, we incurred $559.1 million in acquisition, development and exploration activities, including $455.0 million for the drilling of 437 gross (322.1 net) wells. Of these new wells, 418 resulted in productive completions and 19 were

unsuccessful, yielding a 96% success rate. We have budgeted $350.0 million for development and exploration drilling expenditures in 2007.

Acquisitions and Divestitures

     The following is a summary of our acquisitions and divestitures during the last two years. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information on these acquisitions and divestitures.

     2006 Acquisitions. On August 29, 2006, we acquired a 15% working interest in approximately 170,000 acres of unproved properties in the central Utah Hingeline play for $25.0 million. No producing properties or proved reserves were associated with this acquisition. As part of this transaction, the operator will pay 100% of our drilling and completion costs for the first three wells in the project.

     On August 15, 2006, we acquired 65 producing properties, a gathering line, gas processing plant and 30,437 net acres of leasehold held by production in Michigan. The purchase price was $26.0 million for estimated proved reserves of 1.4 MMBOE as of the acquisition effective date of May 1, 2006, resulting in a cost of $18.55 per BOE of estimated proved reserves. Proved developed reserve quantities represented 99% of the total proved reserves acquired. The average net production from the properties was 0.6 MBOE/d as of the acquisition effective date. We operate 85% of the acquired properties.

     On June 1, 2006, we acquired the Postle field oil gathering system and oil transportation line extending 13 miles from the eastern side of the Postle field to a connection point with an interstate oil pipeline in Hooker, Oklahoma. We purchased the oil gathering system and pipeline for $5.3 million.

     We funded our 2006 acquisitions with cash on hand and borrowings under Whiting Oil and Gas Corporation’s credit agreement.

     2006 Divestitures. During 2006, we sold our interests in several non-core properties for an aggregate amount of $24.4 million in cash for total estimated proved reserves of 1.4 MMBOE as of the effective dates of the divestitures. The divested properties included interests in the Cessford field in Alberta, Canada; Permian Basin of West Texas and New Mexico; and the Ashley Valley field in Uintah County, Utah. The average net production from the divested property interests was 0.4 MBOE/d as of the effective dates of disposition, and we recognized a pre-tax gain on sale of $12.1 million related to these divestitures.

     2005 Acquisitions. We completed four separate acquisitions of producing properties during 2005. The combined purchase price for these four acquisitions was $897.7 million for total estimated proved reserves as of the effective dates of the acquisitions of 133.7 MMBOE, resulting in a cost of $6.72 per BOE of estimated proved reserves.

Business Strategy

     Our goal is to generate meaningful growth in both production and free cash flow by investing in oil and gas projects with attractive rates of return on capital employed. To date, we have achieved this goal largely through the acquisition of additional reserves in our core areas. Based on the extensive property base we have built, we now have several economically attractive opportunities to exploit and develop within our oil and gas properties and several opportunities to explore our acreage positions for production growth and additional proved reserves. Specifically, we have focused, and plan to continue to focus, on the following:

     Developing and Exploiting Existing Properties. Our existing property base and our acquisitions over the past three years have provided us with significant low-risk opportunities for exploitation and development drilling. As of

December 31, 2006, we have identified a drilling inventory of approximately 900 gross wells that we believe will add substantial production over the next five years. Our drilling inventory consists largely of the development of our proved undeveloped reserves on which we have spent significant time evaluating the costs and expected results. Additionally, we have several opportunities to apply enhanced recovery techniques that we expect will increase proved reserves and extend the productive lives of our mature fields. Over the next five years, we anticipate significant increases in production from the North Ward Estes field and Postle field properties we acquired in 2005 through the use of secondary and tertiary recovery techniques, including water and CO₂ floods.

     Growing Through Accretive Acquisitions. Since our initial public offering in November 2003, we have completed twelve acquisitions of producing properties totaling 207.7 MMBOE of estimated total proved reserves. Our experienced team of management, engineering and geoscience professionals has developed and refined an acquisition program designed to increase reserves and complement our existing properties, including identifying and evaluating acquisition opportunities, negotiating and closing purchases, and managing acquired properties. As a result of our disciplined approach, we have achieved significant growth in our core areas at an average cost of $7.02 per BOE of proved reserves through these twelve acquisitions, not including future costs to develop proved undeveloped reserves.

     Pursuing High-Return Organic Reserve Additions. We plan to allocate approximately 75% of our $350.0 million capital budget for 2007 to the development of our existing proved reserves. The remaining 25% will be invested in higher risk drilling, including field extensions drilled outside the current limits of our development projects as well as new exploration, which we believe will increase our proved reserves and future cash flow. We expect to add reserves at costs competitive with our acquisitions. The development of large, unconventional resource plays such as our Piceance basin and Robinson Lake projects have become a central objective of ours. These projects allow us to leverage our technical team’s experience to focus on conventional drilling projects such as our Red River gas play in which we can utilize our 3-D seismic data and other advanced exploration techniques to reduce risk and deliver a high return on investment. We own interests in 897,133 gross (484,495 net) undeveloped acres as well as additional rights to deeper horizons within many of our developed acreage positions.

     Disciplined Financial Approach. Our goal is to remain financially strong, yet flexible, through the prudent management of our balance sheet and active management of commodity price volatility. We have historically funded our acquisitions and growth activity through a combination of equity and debt issuances, bank borrowings and internally generated cash flow, as appropriate, to maintain our strong financial position. To support cash flow generation on our existing properties and secure acquisition economics, we periodically enter into derivative contracts. Typically, we use costless collars to provide an attractive base commodity price level, while maintaining the ability to benefit from improvements in commodity prices.

Competitive Strengths

     We believe that our key competitive strengths lie in our balanced asset portfolio, our experienced management and technical team and our commitment to effective application of new technologies.

     Balanced, Long-Lived Asset Base. As of December 31, 2006, we had interests in 8,437 gross (3,659 net) productive wells across 976,379 gross (472,144 net) developed acres in our five core geographical areas. We believe this geographic mix of properties and organic drilling opportunities, combined with our continuing business strategy of acquiring and exploiting properties in these areas, presents us with multiple opportunities for success in executing our strategy because we are not dependent on any particular producing regions or geological formations. As a result of our acquisitions of the North Ward Estes field and Postle field properties in 2005 we have enhanced the production stability and reserve life of our developed reserves. Additionally, these properties contain identifiable growth opportunities to significantly increase production.

     Experienced Management Team. Our management team averages over 30 years of experience in the oil and gas industry. Our personnel have extensive experience in each of our core geographical areas and in all of our

operational disciplines. In addition, each of our acquisition professionals has at least 25 years of experience in the evaluation, acquisition and operational assimilation of oil and gas properties.

     Commitment to Technology. In each of our core operating areas, we have accumulated detailed geologic and geophysical knowledge and have developed significant technical and operational expertise. In recent years, we have developed considerable expertise in conventional and 3-D seismic imaging and interpretation. Our technical team has access to approximately 1,580 square miles of 3-D seismic data, digital well logs and other subsurface information. This data is analyzed with state of the art geophysical and geological computer resources dedicated to the accurate and efficient characterization of the subsurface oil and gas reservoirs that comprise our asset base. Computer applications enable us to quickly generate reports and schematics on our wells. In addition, our information systems enable us to update our production databases through daily uploads from hand held computers in the field. This commitment to technology has increased the productivity and efficiency of our field operations and development activities.

Proved Reserves

     Our estimated proved reserves as of December 31, 2006 are summarized in the table below.

																		Future
																		Capital
		Oil				Natural Gas				Total				% of Total				Expenditures
		(MMBbl)				(Bcf)				(MMBOE)				Proved				(In thousands)
Permian Basin:
PDP			32.0				39.5				38.6				33	%
PDNP			20.7				9.9				22.2				19	%
PUD			50.4				28.9				55.3				48	%
Total Proved			103.1				78.3				116.1				100	%		$	713.7
Rocky Mountains:
PDP			32.1				66.5				43.1				81	%
PDNP			1.2				5.1				2.1				4	%
PUD			3.8				25.3				8.0				15	%
Total Proved			37.1				96.9				53.2				100	%		$	84.2
Mid-Continent:
PDP			20.5				23.2				24.3				45	%
PDNP			11.9				5.5				12.9				24	%
PUD			15.0				7.7				16.3				31	%
Total Proved			47.4				36.4				53.5				100	%		$	310.0
Gulf Coast:
PDP			1.4				34.1				7.1				56	%
PDNP			0.2				7.0				1.4				11	%
PUD			0.6				21.1				4.1				33	%
Total Proved			2.2				62.2				12.6				100	%		$	43.1
Michigan:
PDP			1.6				34.0				7.3				57	%
PDNP			0.8				1.7				1.1				9	%
PUD			2.8				9.4				4.3				34	%
Total Proved			5.2				45.1				12.7				100	%		$	25.8
Total Company:
PDP			87.6				197.3				120.4				49	%
PDNP			34.8				29.2				39.7				16	%
PUD			72.6				92.4				88.0				35	%
Total Proved			195.0				318.9				248.1				100	%		$	1,176.8

Marketing and Major Customers

     We principally sell our oil and gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is trucked to storage facilities. Our marketing of oil and gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. During 2006, sales to Plains Marketing LP and Valero Energy Corporation accounted for 16% and 12%, respectively, of our total oil and natural gas sales. During 2005, sales to Teppco Crude Oil LLC accounted for 10% of our total oil and natural gas sales. In 2004, no single customer was responsible for generating 10% or more of our total oil and natural gas sales.

Title to Properties

     Our properties are subject to customary royalty interests, liens under indebtedness, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. Whiting Oil and Gas Corporation’s credit agreement is also secured by a first lien on substantially all of our assets. We do not believe that any of these burdens materially interfere with the use of our properties in the operation of our business.

     We believe that we have satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, minimal investigation of title is made at the time of acquisition of undeveloped properties. In most cases, we investigate title and obtain title opinions from counsel only when we acquire producing properties or before commencement of drilling operations.

Competition

     We operate in a highly competitive environment for acquiring properties, marketing oil and gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and gas industry.

Regulation

Regulation of Transportation and Sale of Natural Gas

     The Federal Energy Regulatory Commission (“FERC”) regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 and regulations issued under those Acts. In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and nonprice controls affecting wellhead sales of natural gas, effective January 1, 1993. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, in the future Congress could reenact price controls or enact other legislation with detrimental impact on many aspects of our business.

     Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the FERC that affect the economics of natural gas production, transportation and sales. In addition, the FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry that remain subject to the FERC’s jurisdiction, most notably interstate natural gas transmission companies. These initiatives may also affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis.

     FERC implements The Outer Continental Shelf Lands Act as to transportation and pipeline issues, which requires that all pipelines operating on or across the outer continental shelf provide open access, non-discriminatory transportation service. One of the FERC’s principal goals in carrying out this Act’s mandate is to increase transparency in the market to provide producers and shippers on the outer continental shelf with greater assurance of open access services on pipelines located on the outer continental shelf and non-discriminatory rates and conditions of service on such pipelines.

     We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. In addition, many aspects of these regulatory developments have not become final, but are still pending judicial and final FERC decisions. Regulations implemented by the FERC in recent years could result in an increase in the cost of transportation service on certain petroleum product pipelines. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

     Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.

Regulation of Transportation of Oil

     Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

     Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for crude oil transportation rates that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. As a result, the FERC in February 2003 increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

     Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Regulation of Production

     The production of oil and gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum allowable rates of production from oil and gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, gas and natural gas liquids within its jurisdiction.

     Some of our offshore operations are conducted on federal leases that are administered by Minerals Management Service, or MMS, and are required to comply with the regulations and orders issued by MMS under the Outer Continental Shelf Lands Act. Among other things, we are required to obtain prior MMS approval for any exploration plans we pursue and our development and production plans for these leases. MMS regulations also establish construction requirements for production facilities located on our federal offshore leases and govern the plugging and abandonment of wells and the removal of production facilities from these leases. Under limited circumstances, MMS could require us to suspend or terminate our operations on a federal lease.

     MMS also establishes the basis for royalty payments due under federal oil and gas leases through regulations issued under applicable statutory authority. State regulatory authorities establish similar standards for royalty payments due under state oil and gas leases. The basis for royalty payments established by MMS and the state regulatory authorities is generally applicable to all federal and state oil and gas lessees. Accordingly, we believe that the impact of royalty regulation on our operations should generally be the same as the impact on our competitors.

     The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental Regulations

     General. Our oil and gas exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency (the “EPA”) issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or that may result in injunctive relief for failure to comply. These laws and regulations may require the acquisition of a permit before drilling or facility construction commences, restrict the types, quantities and concentrations of various materials that can be released into the environment in connection with drilling and production activities, limit or prohibit project siting, construction, or drilling activities on certain lands laying within wilderness, wetlands, ecologically sensitive and other protected areas, require remedial action to prevent pollution from former operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations. The EPA and analogous state agencies may delay or refuse the issuance of required permits or otherwise include onerous or limiting permit conditions that may have a significant adverse impact on our ability to conduct operations. The regulatory burden on the oil and gas industry increases the cost of doing business and consequently affects its profitability.

     Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly material handling, storage, transport, disposal or cleanup requirements could materially and adversely affect our operations and financial position, as well as those of the oil and gas industry in general. While we believe that we are in substantial compliance with current applicable environmental laws and regulations and have not experienced any material adverse effect from compliance with these environmental requirements, there is no assurance that this trend will continue in the future.

     The environmental laws and regulations which have the most significant impact on the oil and gas exploration and production industry are as follows:

     Superfund. The Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as “CERCLA” or “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the “owner” or “operator” of a disposal site or sites where a release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, such persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal

injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our ordinary operations, we may generate material that may fall within CERCLA’s definition of a “hazardous substance.” Consequently, we may be jointly and severally liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these materials have been disposed or released.

     We currently own or lease, and in the past have owned or leased, properties that for many years have been used for the exploration and production of oil and gas. Although we and our predecessors have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other materials may have been disposed or released on, under, or from the properties owned or leased by us or on, under, or from other locations where these hydrocarbons and materials have been taken for disposal. In addition, many of these owned and leased properties have been operated by third parties whose management and disposal of hydrocarbons and materials were not under our control. Similarly, the disposal facilities where discarded materials are sent are also often operated by third parties whose waste treatment and disposal practices may not be adequate. While we only use what we consider to be reputable disposal facilities, we might not know of a potential problem if the disposal occurred before we acquired the property or business, if the problem itself is not discovered until years later. Our properties, adjacent affected properties, the disposal sites, and the material itself may be subject to CERCLA and analogous state laws. Under these laws, we could be required:

	•		to remove or remediate previously disposed materials, including materials disposed or released by prior owners or operators or other third parties;
	•		to clean up contaminated property, including contaminated groundwater; or
	•		to perform remedial operations to prevent future contamination, including the plugging and abandonment of wells drilled and left inactive by prior owners and operators.

     At this time, we do not believe that we are a potentially responsible party with respect to any Superfund site and we have not been notified of any claim, liability or damages under CERCLA.

     Oil Pollution Act. The Oil Pollution Act of 1990, also known as “OPA,” and regulations issued under OPA impose strict, joint and several liability on “responsible parties” for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permittee of the area in which an offshore facility is located. The OPA establishes a liability limit for onshore facilities of $350.0 million, while the liability limit for offshore facilities is the payment of all removal costs plus up to $75.0 million in other damages, but these limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a cleanup. The OPA also requires the lessee or permittee of the offshore area in which a covered offshore facility is located to establish and maintain evidence of financial responsibility in the amount of $35.0 million ($10.0 million if the offshore facility is located landward of the seaward boundary of a state) to cover liabilities related to an oil spill for which such person is statutorily responsible. The amount of financial responsibility required under OPA may be increased up to $150.0 million, depending on the risk represented by the quantity or quality of oil that is handled by the facility. Any failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to administrative, civil or criminal enforcement actions. We believe we are in compliance with all applicable OPA financial responsibility obligations. Moreover, we are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on us.

     Resource Conservation Recovery Act. The Resource Conservation and Recovery Act, also known as “RCRA,” is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a

“generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. RCRA and many state counterparts specifically exclude from the definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy” and thus we are not required to comply with a substantial portion of RCRA’s requirements because our operations generate minimal quantities of hazardous wastes. However, these wastes may be regulated by EPA or state agencies as solid waste. In addition, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils, may be regulated as hazardous waste. Although we do not believe the current costs of managing our materials constituting wastes as they are presently classified to be significant, any repeal or modification of the oil and gas exploration and production exemption by administrative, legislative or judicial process, or modification of similar exemptions in analogous state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses.

     Clean Water Act. The Federal Water Pollution Control Act of 1972, or the Clean Water Act (the “CWA”), imposes restrictions and controls on the discharge of produced waters and other pollutants into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. The CWA and certain state regulations prohibit the discharge of produced water, sand, drilling fluids, drill cuttings, sediment and certain other substances related to the oil and gas industry into certain coastal and offshore waters without an individual or general National Pollutant Discharge Elimination System discharge permit.

     Historically, the EPA had regulations under the authority of the CWA that required certain oil and gas exploration and production projects to obtain permits for construction projects with storm water discharges. However, the Energy Policy Act of 2005 nullified most of the EPA regulations that required permitting of oil and gas construction projects. There are still some States that regulate the discharge of storm water from oil and gas construction projects. Costs may be associated with the treatment of wastewater and/or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. In Section 40 CFR 112 of the regulations, the EPA promulgated the Spill Prevention, Control, and Countermeasure, or SPCC, regulations, which require certain oil containing facilities to prepare plans and meet construction and operating standards. The SPCC regulations were revised in 2002 and will require the amendment of SPCC plans and the modification of spill control devices at many facilities. The due date for having plans completed and control devices in place was extended on December 12, 2005 with the new compliance date being October 31, 2007. On December 26, 2006 the EPA proposed an additional extension of the compliance dates until July 1, 2009 for both completion and implementation of the Plan. This proposed rule is expected to be finalized in the near future. The extension will allow time for the EPA to complete additional rule amendments and guidance documents. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution and that any amendment and subsequent implementation of our SPCC plans will be performed in a timely manner and not have a significant impact on our operations.

     Clean Air Act. The Clean Air restricts the emission of air pollutants from many sources, including oil and gas operations. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. More stringent regulations governing emissions of toxic air pollutants are being developed by the EPA, and may increase the costs of compliance for some facilities. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold or have applied for all permits necessary to our operations.

     Consideration of Environmental Issues in Connection with Governmental Approvals. Our operations frequently require licenses, permits and/or other governmental approvals. Several federal statutes, including the Outer Continental Shelf Lands Act, the National Environmental Policy Act, and the Coastal Zone Management Act require

federal agencies to evaluate environmental issues in connection with granting such approvals and/or taking other major agency actions. The Outer Continental Shelf Lands Act, for instance, requires the U.S. Department of Interior to evaluate whether certain proposed activities would cause serious harm or damage to the marine, coastal or human environment. Similarly, the National Environmental Policy Act requires the Department of Interior and other federal agencies to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency would have to prepare an environmental assessment and, potentially, an environmental impact statement. The Coastal Zone Management Act, on the other hand, aids states in developing a coastal management program to protect the coastal environment from growing demands associated with various uses, including offshore oil and gas development. In obtaining various approvals from the Department of Interior, we must certify that we will conduct our activities in a manner consistent with these regulations.

Employees

     As of December 31, 2006, we had 359 full-time employees, including 27 senior level geoscientists and 35 petroleum engineers. Our employees are not represented by any labor unions. We consider our relations with our employees to be satisfactory, and have never experienced a work stoppage or strike.

Available Information

     We maintain a website at the address www.whiting.com. We are not including the information contained on our website as part of, or incorporating it by reference into, this report. We make available free of charge (other than an investor’s own Internet access charges) through our website our Annual Report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and amendments to these reports, as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the Securities and Exchange Commission.

Item 1A. Risk Factors

     You should carefully consider each of the risks described below, together with all of the other information contained in this Annual Report on Form 10-K, before making an investment decision with respect to our securities. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially and adversely affected and you may lose all or part of your investment.

A substantial or extended decline in oil and gas prices may adversely affect our business, financial condition or results of operations.

     The price we receive for our oil and gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Crude oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

	•		changes in global supply and demand for oil and gas;
	•		the actions of the Organization of Petroleum Exporting Countries;
	•		the price and quantity of imports of foreign oil and gas;
	•		political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity;
	•		the level of global oil and gas exploration and production activity;

	•		the level of global oil and gas inventories;
	•		weather conditions;
	•		technological advances affecting energy consumption;
	•		domestic and foreign governmental regulations;
	•		proximity and capacity of oil and gas pipelines and other transportation facilities;
	•		the price and availability of competitors’ supplies of oil and gas in captive market areas; and
	•		the price and availability of alternative fuels.

     Lower oil and gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and gas that we can produce economically. A substantial or extended decline in oil or gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. Lower oil and gas prices may also reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders based on the collateral value of our proved reserves that have been mortgaged to the lenders.

Drilling for and producing oil and gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

     Our future success will depend on the success of our development, exploitation, production and exploration activities. Our oil and gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Please read “— Reserve estimates depend on many assumptions that may turn out to be inaccurate . . .” for a discussion of the uncertainty involved in these processes. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:

	•		delays imposed by or resulting from compliance with regulatory requirements;
	•		pressure or irregularities in geological formations;
	•		shortages of or delays in obtaining equipment, including drilling rigs, and qualified personnel;
	•		equipment failures or accidents;
	•		adverse weather conditions, such as hurricanes and tropical storms;
	•		reductions in oil and gas prices; and
	•		title problems.

Our acquisition activities may not be successful.

     As part of our growth strategy, we have made and may continue to make acquisitions of businesses and properties. However, suitable acquisition candidates may not continue to be available on terms and conditions we find acceptable, and acquisitions pose substantial risks to our business, financial condition and results of operations. In pursuing acquisitions, we compete with other companies, many of which have greater financial and other resources to acquire attractive companies and properties. The following are some of the risks associated with acquisitions, including any future acquisitions and our recently completed acquisitions:

	•		some of the acquired businesses or properties may not produce revenues, reserves, earnings or cash flow at anticipated levels;
	•		we may assume liabilities that were not disclosed to us or that exceed our estimates;
	•		we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;
	•		acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures; and
	•		we may issue additional debt securities or equity related to future acquisitions.

The development of the proved undeveloped reserves in the North Ward Estes and Postle fields may take longer and may require higher levels of capital expenditures than we currently anticipate.

     As of December 31, 2006, undeveloped reserves comprised 54% of the North Ward Estes field’s total estimated proved reserves and 34% of Postle field’s estimated total proved reserves. In order to fully develop these reserves, we expect to incur future development costs of $656.0 million at the North Ward Estes field and $302.6 million at the Postle field. During 2006, the estimated capital expenditures necessary to develop the proved reserves at the North Ward Estes field and Postle field increased substantially. The increase was due to several factors including equipment and service cost inflation, higher CO₂ unit costs and volumes, higher costs associated with the expanded scope of previously identified projects as well as new projects identified during 2006. Together, these fields encompass 82% of our estimated total future development costs related to proved reserves. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. In addition, the development of these reserves will require the use of enhanced recovery techniques, including water flood and CO₂ injection installations, the success of which is less predictable than traditional development techniques. Therefore, ultimate recoveries from these fields may not match current expectations.

Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.

     In order to finance acquisitions of additional producing properties, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments or other means. These changes in capitalization may significantly affect our risk profile. Additionally, significant acquisitions or other transactions can change the character of our operations and business. The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. Furthermore, we may not be able to obtain external funding for future acquisitions or other transactions or to obtain external funding on terms acceptable to us.

Properties that we acquire may not produce as projected, and we may be unable to identify liabilities associated with the properties or obtain protection from sellers against them.

     Our business strategy includes a continuing acquisition program. During 2006 and 2005, we completed five separate acquisitions of producing properties with a combined purchase price of $923.7 million for estimated proved reserves as of the effective dates of the acquisitions of 135.1 MMBOE, representing an average cost of $6.84 per BOE of estimated proved reserves. The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following:

	•		the amount of recoverable reserves;
	•		future oil and gas prices;
	•		estimates of operating costs;
	•		estimates of future development costs;
	•		estimates of the costs and timing of plugging and abandonment; and
	•		potential environmental and other liabilities.

     Our assessment will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. In the course of our due diligence, we may not inspect every well, platform or pipeline. Inspections may not reveal structural and environmental problems, such as pipeline corrosion or groundwater contamination, when they are made. We may not be able to obtain contractual indemnities from the seller for liabilities that it created. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

If oil and gas prices decrease, we may be required to take write-downs of the carrying values of our oil and gas properties.

     Accounting rules require that we review periodically the carrying value of our oil and gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and gas properties. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

Our debt level and the covenants in the agreements governing our debt could negatively impact our financial condition, results of operations and business prospects.

     As of December 31, 2006, we had $380.0 million in outstanding consolidated indebtedness under Whiting Oil and Gas Corporation’s credit agreement with $495.0 million of available borrowing capacity, as well as $620.0 million of Senior Subordinated Notes outstanding. We are permitted to incur additional indebtedness, provided we meet certain requirements in the indentures governing our senior subordinated notes and Whiting Oil and Gas Corporation’s credit agreement.

     Our level of indebtedness, and the covenants contained in the agreements governing our debt, could have important consequences for our operations, including:

	•		increasing our vulnerability to general adverse economic and industry conditions and detracting from our ability to withstand successfully a downturn in our business or the economy generally;
	•		requiring us to dedicate a substantial portion of our cash flow from operations to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;
	•		limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities;
	•		limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
	•		placing us at a competitive disadvantage relative to other less leveraged competitors; and
	•		making us vulnerable to increases in interest rates, because debt under Whiting Oil and Gas Corporation’s credit agreement may be at variable rates.

     We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the acceleration of our repayment of outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions. Moreover, the borrowing base limitation on Whiting Oil and Gas Corporation’s credit agreement is periodically redetermined based on an evaluation of our reserves. Upon a redetermination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to repay a portion of our bank debt.

     We may not have sufficient funds to make such repayments. If we are unable to repay our debt out of cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. We may not be able to generate sufficient cash flow to pay the interest on our debt, or future borrowings, equity financings or proceeds from the sale of assets may not be available to pay or refinance such debt. The terms of our debt, including Whiting Oil and Gas Corporation’s credit agreement, may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offering or other financing. We may not be able to successfully complete any such offering, refinancing or sale of assets.

The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business.

     The indentures governing our senior subordinated notes and Whiting Oil and Gas Corporation’s credit agreement contain various restrictive covenants that limit our management’s discretion in operating our business. In particular, these agreements will limit our and our subsidiaries’ ability to, among other things:

	•		pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our subordinated debt;
	•		make loans to others;
	•		make investments;
	•		incur additional indebtedness or issue preferred stock;

	•		create certain liens;
	•		sell assets;
	•		enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
	•		consolidate, merge or transfer all or substantially all of the assets of us and our restrict subsidiaries taken as a whole;
	•		engage in transactions with affiliates;
	•		enter into hedging contracts;
	•		create unrestricted subsidiaries; and
	•		enter into sale and leaseback transactions.

     In addition, Whiting Oil and Gas Corporation’s credit agreement also requires us to maintain a certain working capital ratio and a certain debt to EBITDAX (as defined in the credit agreement) ratio.

     If we fail to comply with the restrictions in the indentures governing our senior subordinated notes or Whiting Oil and Gas Corporation’s credit agreement or any other subsequent financing agreements, a default may allow the creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, lenders may be able to terminate any commitments they had made to make available further funds.

Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our oil and gas reserves.

     The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of oil and gas reserves. To date, we have financed capital expenditures primarily with bank borrowings and cash generated by operations. We intend to finance our future capital expenditures with cash flow from operations and our existing financing arrangements. Our cash flow from operations and access to capital are subject to a number of variables, including:

	•		our proved reserves;
	•		the level of oil and gas we are able to produce from existing wells;
	•		the prices at which oil and gas are sold; and
	•		our ability to acquire, locate and produce new reserves.

     If our revenues or the borrowing base under our bank credit agreement decreases as a result of lower oil and gas prices, operating difficulties, declines in reserves or for any other reason, then we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may, from time to time, need to seek additional financing. There can be no assurance as to the availability or terms of any additional financing.

     If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and gas reserves.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

     The process of estimating oil and gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves referred to in this Annual Report on Form 10-K.

     In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and gas reserves are inherently imprecise.

     Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves referred to in this Annual Report on Form 10-K. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.

     You should not assume that the present value of future net revenues from our proved reserves referred to in this Annual Report on Form 10-K is the current market value of our estimated oil and gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. If natural gas prices decline by $0.10 per Mcf, then the standardized measure of discounted future net cash flows of our estimated proved reserves as of December 31, 2006 would have decreased from $2,392.2 million to $2,382.1 million. If oil prices decline by $1.00 per Bbl, then the standardized measure of discounted future net cash flows of our estimated proved reserves as of December 31, 2006 would have decreased from $2,392.2 million to $2,340.9 million.

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

     Oil and gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. In certain areas drilling and other oil and gas activities can only be conducted during the spring and summer months. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. Resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

Prospects that we decide to drill may not yield oil or gas in commercially viable quantities.

     We describe some of our current prospects and our plans to explore those prospects in this Annual Report on Form 10-K. A prospect is a property on which we have identified what our geoscientists believe, based on available

seismic and geological information, to be indications of oil or gas. Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or gas will be present or, if present, whether oil or gas will be present in commercial quantities. The analogies we draw from available data from other wells, more fully explored prospects or producing fields may not be applicable to our drilling prospects.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and gas operations.

     We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and gas, including the possibility of:

	•		environmental hazards, such as uncontrollable flows of oil, gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
	•		abnormally pressured formations;
	•		mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
	•		fires and explosions;
	•		personal injuries and death; and
	•		natural disasters.

     Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to our company. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, then it could adversely affect us.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

     If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure of an operator of our wells to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells, and use of technology. Because we do not have a majority interest in most wells we do not operate, we may not be in a position to remove the operator in the event of poor performance.

Our use of 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and gas, which could adversely affect the results of our drilling operations.

     Even when properly used and interpreted, 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, some of our drilling activities may not be successful or economical and our overall drilling success rate or our drilling success rate for activities in a particular area could decline. We often gather 3-D seismic over large areas. Our interpretation of seismic data delineates for us those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data and, in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, it would result in our having made substantial expenditures to acquire and analyze 3-D data without having an opportunity to attempt to benefit from those expenditures.

Market conditions or operational impediments may hinder our access to oil and gas markets or delay our production.

     Market conditions or the unavailability of satisfactory oil and gas transportation arrangements may hinder our access to oil and gas markets or delay our production. The availability of a ready market for our oil and gas production depends on a number of factors, including the demand for and supply of oil and gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for a lack of a market or because of inadequacy or unavailability of gas pipeline or gathering system capacity. If that were to occur, then we would be unable to realize revenue from those wells until production arrangements were made to deliver to market.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

     Exploration, development, production and sale of oil and gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:

	•		discharge permits for drilling operations;
	•		drilling bonds;
	•		reports concerning operations;
	•		the spacing of wells;
	•		unitization and pooling of properties; and
	•		taxation.

     Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our

costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.

Our operations may incur substantial liabilities to comply with the environmental laws and regulations.

     Our oil and gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities, and concentration of materials that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, incurrence of investigatory or remedial obligations, or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly material handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position, or financial condition as well as those of the oil and gas industry in general. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed. Federal law and some state laws also allow the government to place a lien on real property for costs incurred by the government to address contamination on the property.

Unless we replace our oil and gas reserves, our reserves and production will decline, which would adversely affect our cash flows and income.

     Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and gas reserves and production, and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire additional reserves to replace our current and future production.

The loss of senior management or technical personnel could adversely affect us.

     To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including James J. Volker, our Chairman, President and Chief Executive Officer; James T. Brown, our Vice President, Operations; J. Douglas Lang, our Vice President, Reservoir Engineering/Acquisitions; David M. Seery, our Vice President of Land; Michael J. Stevens, our Vice President and Chief Financial Officer; or Mark R. Williams, our Vice President, Exploration and Development, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.

     Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our development and exploration operations, which could have a material adverse effect on our business, financial condition, results of operations or cash flows.

Competition in the oil and gas industry is intense, which may adversely affect our ability to compete.

     We operate in a highly competitive environment for acquiring properties, marketing oil and gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

Our use of oil and gas price hedging contracts involves credit risk and may limit future revenues from price increases and result in significant fluctuations in our net income.

     We enter into hedging transactions for our oil and gas production to reduce our exposure to fluctuations in the price of oil and gas. Our hedging transactions have to date consisted of financially settled crude oil and natural gas forward sales contracts, primarily costless collars, placed with major financial institutions. As of December 31, 2006, we have contracts maturing in 2007 covering the sale of between 410,000 and 450,000 barrels of oil per month and 1,600,000 MMbtu of gas per month. All our oil hedges expire in December of 2008, and all our gas hedges expire in March of 2007. Whiting Oil and Gas Corporation’s credit agreement required us to hedge at least 55% of our total forecasted production from the Postle properties and the North Ward Estes properties for the period through March 31, 2007 for gas and December 31, 2008 for oil. These hedges were put in place during the third quarter of 2005. See “Quantitative and Qualitative Disclosure about Market Risk — Commodity Risk” for pricing and a more detailed discussion of our hedging transactions.

     We may in the future enter into these and other types of hedging arrangements to reduce our exposure to fluctuations in the market prices of oil and gas. Hedging transactions expose us to risk of financial loss in some circumstances, including if production is less than expected, the other party to the contract defaults on its obligations or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. Hedging transactions may limit the benefit we would have otherwise received from increases in the price for oil and gas. Furthermore, if we do not engage in hedging transactions, then we may be more adversely affected by declines in oil and gas prices than our competitors who engage in hedging transactions. Additionally, hedging transactions may expose us to cash margin requirements.

Item 1B. Unresolved Staff Comments

     None.

Item 2. Properties

Summary of Oil and Gas Properties and Projects

Permian Basin Region

     Our Permian Basin operations include assets in Texas and New Mexico. As of December 31, 2006, the Permian Basin region contributed 116.1 MMBOE (89% oil) of estimated proved reserves to our portfolio of operations, which represented 47% of our total estimated proved reserves. Approximately 96% of the proved reserves of our Permian Basin operations are related to properties in Texas.

     North Ward Estes. The North Ward Estes field includes six base leases with 100% working interest in 58,000 gross and net acres in Ward and Winkler Counties, Texas. As of December 31, 2006, there were approximately 935 producing wells and 440 injection wells. The Yates Formation at 2,600 feet is the primary producing zone with additional production from other zones including the Queen at 3,000 feet. We also have the rights to deeper horizons under 34,140 gross acres in the North Ward Estes field. The North Ward Estes properties produced at an estimated average net daily rate of 5,370 Bopd (including NGLs) and 5,880 Mcf/d of gas during the month of December 2006. In the North Ward Estes field, the estimated proved reserves as of December 31, 2006 were 20% PDP, 26% PDNP and 54% PUD.

     The North Ward Estes field was initially developed in the 1930’s and full scale waterflooding was initiated in 1955. A CO₂ enhanced recovery project was implemented in the core of the field in 1989, but was terminated in 1996 after a successful top lease by a third party. We reinitiated water injection in 2006 and have successfully re-pressured the pilot area for the resumptions of the CO₂ flood. We began construction of a gas plant to process and separate the CO₂ from the produced gas in the fourth quarter of 2006, and we plan to begin CO₂ injection late in the first quarter of 2007. A contract for the future purchase of significant CO₂ volumes was executed during 2006.

     We also have interests in certain other fields within the Permian Basin of Texas and New Mexico, including 2,250 producing oil and gas wells. These properties produced at an estimated average net daily rate of 7,990 Bopd (including NGLs) and 18,340 Mcf/d of gas during the month of December 2006.

     Would Have Field. We own an 87% operated working interest in the Would Have field in Howard County, Texas, currently producing from 57 active wells. Discovered in 2001, this field produces from two sub-units of the Clearfork Formation, the Would Have and the Dillard Limestones. Waterflood expansion into the eastern half of the field is currently underway. During 2006 we drilled two successful Varel (San Andres) tests, and plans are underway to participate in a “Wolfberry” (Wolfcamp & Sprayberry) test on the lease.

     Keystone South, Martin and Flying W Fields. We own a 100% working interest and operate these three fields located on the Western edge of the Midland Basin. Production comes from the Clearfork Formation, with additional production from the Wichita, Wolfcamp, Devonian, Silurian, McKee and Ellenburger Formations. During 2006 we drilled a total of seven wells in these fields. Based on the 2006 success, we are planning additional wells for 2007.

Rocky Mountain Region

     Our Rocky Mountain operations include assets in the states of North Dakota, Montana, Colorado, Utah, Wyoming and California. As of December 31, 2006, our estimated proved reserves in the Rocky Mountain region were 53.2 MMBOE (70% oil), which represented 21% of our total estimated proved reserves. Approximately 51% and 31% of the proved reserves of our Rocky Mountain operations are related to assets in North Dakota and Wyoming, respectively.

     Robinson Lake Bakken Play. The Bakken Formation is a low permeability, unconventional reservoir consisting of highly oil saturated shale, dolomite and fine grained sand. Horizontal drilling and advanced stimulation techniques have been successfully employed in the drilling of hundreds of wells in the Elm Coulee field in Montana and more recently in the North Dakota portion of the Williston Basin. In early 2005, we embarked on an aggressive leasing program and have since acquired approximately 116,000 gross (81,000 net) acres primarily in Mountrail County, North Dakota for the purpose of developing a Bakken resource drilling program. To date, we have drilled and completed two exploratory wells. We are encouraged by our Bartleson State #44-1H well, which is currently flowing oil and appears to be an economic well. We are currently drilling our third well and conducting a 98 square mile 3-D seismic survey in order to assist in our selection of future drilling locations.

     Red River Gas Drilling Program. In 2004 we began acquiring 3-D seismic data over several Red River Formation prospects in the deeper, gas bearing part of the Williston Basin for the purpose of defining structure and reservoir distribution. To date we have acquired seven 3-D surveys in Billings, McKenzie and Williams Counties

totaling 165 square miles which we have used to target eight new wells. Eight of these wells have resulted in successful completions with average initial rates of 3,100 Mcf/d. We currently plan to drill four to eight wells during 2007.

     Billings Nose Drilling Program. We have established a high concentration of producing wells in the Billings Nose area of Billings County, North Dakota. These assets include the Big Stick Madison Unit and North Elkhorn Ranch Unit along with much of the acreage located between these two fields. We have acquired 99 square miles of 3-D seismic data in this area and have since identified multiple opportunities in a variety of reservoirs including the Red River, Duperow, Bakken and Mission Canyon Formations. In 2006, we drilled one Mission Canyon well in the Big Stick Unit and three horizontal Mission Canyon wells in North Elkhorn Ranch. Additional drilling is planned in both of these units in 2007.

     Nisku A Drilling Program. We made a significant exploration discovery in 2004 in western Billings County, North Dakota in the Nisku A zone and drilled ten wells in 2004. In 2005 we drilled eight casing-exit wells and drilled or participated in 13 grass-roots horizontal wells. During 2006 we participated in 20 grass-roots horizontal wells. We plan additional development drilling in the area and are studying the potential for additional recovery through the implementation of a waterflood.

     Green River Basin—Siberia Ridge. Siberia Ridge is within the greater Wamsutter Arch area of Sweetwater County, Wyoming and produces from a continuous-phase gas accumulation in the Cretaceous Almond Formation at 10,500 feet. In 2004, the spacing rules governing the well density in the Siberia Ridge field were adjusted to allow for up to two wells per 160 acres. This new configuration resulted in a total of 44 additional potential locations on our acreage. Because of lease stipulations on this Federal acreage, drilling operations can be initiated August 1st and must end by February 1st of the following year. We have been able to maintain a single well drilling program by moving the rig between Anderson Canyon (described below) and Siberia Ridge.

     Our development program commenced in mid-2005 and continued in 2006 with the drilling of ten new wells. We have implemented a focused effort on the identification, selective perforation and stimulation of the various natural gas productive zones within the Almond Formation in order to optimize production. Completion operations are currently underway with encouraging initial rates.

     Green River Basin — Anderson Canyon. Anderson Canyon, North Anderson Canyon, Bird Canyon, and McDonald Draw fields are all located on the LaBarge Platform in Southwest Wyoming. We drilled six wells in 2006 and plan to drill ten wells in 2007. Initial results are positive with initial production rates ranging from 500 Mcf/d to over 1,000 Mcf/d. We believe the remaining potential is primarily in the Frontier formation at 8,800 feet.

     Sulphur Creek-Boies Ranch Area, Rio Blanco County, Colorado. The Sulphur Creek Area in the North Central Piceance Basin has the potential to be a focal point of our activity through 2009. We acquired the majority of 16,813 gross (3,638 net) acres in the 2004 Equity Oil Company acquisition. We are currently supplementing our leasehold in the area. Drilling by third parties near our leasehold has demonstrated the presence of a continuous-phase gas resource in the Williams Fork Formation with up-hole potential in the Wasatch Formation. We finished the drilling of the first well on the Boies Ranch acreage in early 2007, and we have planned three additional wells for the remainder of the year. An additional 73 Williams Fork locations are planned assuming typical 20 acre spacing. On the Boies Ranch acreage we own the acreage in fee, meaning we own the surface and minerals and there are minimal landowner burdens. As a result, we have a 50% average working interest with a 49% average net revenue interest in the Boies Ranch acreage.

     Utah Hingeline. We own a 15%, non-operated, working interest in approximately 170,000 acres of leasehold in the central Utah Hingeline play. This acreage covers several prospect leads which have been identified along trend with the recent Covenant Field discovery in Sevier County, Utah. As part of our acquisition of this property, the operator will pay 100% our drilling and completion costs for the first three wells in the project. The first of these three

has been drilled but did not find commercial quantities of hydrocarbons. The remaining two wells will likely be drilled during 2007.

Mid-Continent Region

     Our Mid-Continent operations include assets in Oklahoma, Arkansas and Kansas. As of December 31, 2006, the Mid-Continent region contributed 53.5 MMBOE (88% oil) of proved reserves to our portfolio of operations, which represented 22% of our total estimated proved reserves. The majority of the proved value within our Mid-Continent operations is related to properties in the Postle field.

     Postle Field. The Postle field, located in Texas County, Oklahoma, includes five producing units and one producing lease covering a total of approximately 25,600 gross acres (24,225 net) with working interests of 94% to 100%. Three of the units are currently active CO₂ enhanced recovery projects. As of December 31, 2006, there were 127 producing wells and 107 injection wells completed in the Morrow zone at 6,100 feet. The Postle field is the largest Morrow oil field in the U.S. The Postle properties produced at an estimated average net daily rate of 4,112 Bopd (including NGLs) and 930 Mcf/d of gas during the month of December 2006. In the Postle field, the estimated proved reserves as of December 31, 2006 were 40% PDP, 26% PDNP and 34% PUD.

     The Postle field was initially developed in the early 1960’s and unitized for waterflood in 1967. Enhanced recovery projects using CO₂ were initiated in 1995 and continue in three of the five units. Operations are underway to expand CO₂ injection into the rest of the units, with four drilling rigs and three workover rigs in the field. These expansion projects include the restoration of shut-in wells and the drilling of new producing and injection wells.

     We are the sole owner of the Dry Trails Gas Plant located in the Postle field. This gas processing plant separates CO₂ gas from the produced wellhead mixture of hydrocarbon and CO₂ gas, so that the CO₂ gas can be reinjected into the producing formation. Construction began in mid-2006 to increase the plant capacity from its current capacity of 40,000 Mcf/d to 80,000 Mcf/d by the fourth quarter of 2007 to support the expanded CO₂ injection projects.

     In addition to the producing assets and processing plant, we have a 60% interest in the 120 mile TransPetco operated CO₂ transportation pipeline, thereby assuring the delivery of CO₂ to the Postle field at a fair tariff. A long-term CO₂ purchase agreement was executed in 2005 to provide the necessary CO₂ for the expansion planned in the field.

Gulf Coast Region

     Our Gulf Coast operations include assets located in Texas, Louisiana and Mississippi. As of December 31, 2006, the Gulf Coast region contributed 12.6 MMBOE (18% oil) of proved reserves to our portfolio of operations, which represented 5% of our total estimated proved reserves. Approximately 80% of the proved reserves of our Gulf Coast operations are related to properties in Texas.

     Stuart City Reef Trend. We have an average 65% working interest in five fields in the Stuart City Reef Trend: Word North, Yoakum, Kawitt, Sweet Home, and Three Rivers. Production in the Stuart City Reef Trend comes primarily from the Edwards, Wilcox, and Sligo Formations at depths between 7,000 and 16,000 feet.

     In late 2003, we began a combination development and exploration program targeting multiple sandstone gas reservoirs within the Wilcox Formation. We have been active in this area, drilling nine wells in 2005 and three wells in 2006. In addition, we are currently planning to conduct a 40 square mile 3-D seismic program designed to expand this play into new areas. Recent success with vertical Edwards’ completions has improved the economics of this gas play. For 2007, we are planning to participate in the drilling of up to five vertical Edwards wells with the potential for Wilcox pay to be encountered in each wellbore.

     Vicksburg Trend. Our non-operated holdings in the Vicksburg and Frio Trends are concentrated primarily in the South Midway field in San Patricio County, Texas and the Agua Dulce field. During 2005, we drilled or participated in eleven new wells targeting multiple gas productive sands in the Vicksburg and Frio Formations at depths between 10,000 and 14,500 feet. Results from this program encouraged us to drill seven additional wells in South Midway and one additional well in Agua Dulce during 2006.

Michigan Region

     Production in Michigan can be divided into two groups. The majority of the reserves are in non-operated Antrim Shale wells located in the northern part of the state. The remainder of the Michigan reserves are typified by more conventional oil and gas production located in the central and southern parts of the state. We also operate the West Branch and the recently acquired Reno gas processing plants. These plants are in good mechanical condition and capable of handling additional production. The West Branch Plant gathers production from the Clayton, West Branch and other smaller fields.

     Antrim Production. In northern Michigan, we own an interest in over 50 multi-well Antrim Shale gas projects with proved producing reserves and ongoing development drilling. During 2006, we participated in the drilling and completion of 20 Antrim Shale wells. In 2007, we plan to continue to pursue similar development drilling opportunities.

     Conventional Production. Our conventional production is primarily from the Prairie du Chien, Glenwood and Trenton Black River Formations, located in central and southern Michigan. We own interests in 49 fields in this area, of which we operate 24.

     In August 2006, we closed on an acquisition of 65 wells producing a total of 638 net Bopd. The acquisition was 99% proved producing reserves, of which 55% was oil. Based on our evaluation of the properties and our experience in Clayton Unit, we are optimistic about the potential upside that may exist in these mature fields.

     During late 2005, we drilled two Glenwood/Prarie du Chien (“PdC”) wells in the Clayton Unit. The target reservoir was the upper PdC, which historically had been the pay interval in the field. Both of these wells encountered hydrocarbons in the Middle interval of the PdC, which had not previously produced. The initial completion in both of these wells was in the middle PdC and both wells still have the original target reservoir behind pipe. We have been encouraged by the results. We assisted a local drilling contractor with the financing necessary to assemble another drilling rig capable of drilling to the PdC. This rig is now drilling the first well in a multi-year drilling program.

Acreage

     The following table summarizes gross and net developed and undeveloped acreage at December 31, 2006 by state. Net acreage is our percentage ownership of gross acreage. Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.

		Developed Acreage								Undeveloped Acreage								Total Acreage
		Gross				Net				Gross				Net				Gross				Net
California			35,956				10,909				3,273				277				39,229				11,185
Colorado			34,390				18,091				33,984				8,273				68,374				26,364
Kansas			850				561				75,849				74,506				76,699				75,066
Louisiana			41,804				10,700				5,294				2,447				47,098				13,147
Michigan			150,079				71,645				21,601				17,936				171,680				89,580
Montana			38,400				12,448				73,939				32,363				112,339				42,533
North Dakota			152,595				80,939				314,874				199,823				467,469				280,762
Oklahoma			63,249				39,460				171				32				63,420				39,492
Texas			316,527				151,325				93,658				70,031				410,185				223,296
Utah			20,677				11,343				213,254				48,568				233,931				59,911
Wyoming			106,928				56,580				60,039				29,453				166,967				86,299
Other*			14,924				8,143				1,197				786				16,121				8,929
Total			976,379				472,144				897,133				484,495				1,873,512				956,564

Production History

     The following table presents historical information about our produced oil and gas volumes:

		Year Ended December 31,
		2006				2005				2004
Oil production (MMbbls)			9.8				7.0				3.7
Natural gas production (Bcf)			32.1				30.3				25.1
Total production (MMBOE)			15.2				12.1				7.9
Daily production (MBOE/d)			41.5				33.1				21.6
Average sales prices:
Oil (per Bbl)		$	57.27			$	51.26			$	38.72
Effect of oil hedges on average price (per Bbl)		$	(0.95	)		$	(2.72	)		$	(1.33	)
Oil net of hedging (per Bbl)		$	56.32			$	48.54			$	37.39
Natural gas (per Mcf)		$	6.59			$	7.03			$	5.56
Effect of natural gas hedges on average price (per Mcf)		$	0.06			$	(0.47	)		$	—
Natural gas net of hedging (per Mcf)		$	6.65			$	6.56			$	5.56
Per BOE data:
Sales price (net of hedging)		$	50.52			$	44.70			$	35.23
Lease operating expenses		$	12.12			$	9.24			$	6.91
Production taxes		$	3.11			$	2.99			$	2.14
Depreciation, depletion and amortization expenses		$	10.74			$	8.08			$	6.89
General and administrative expenses		$	2.49			$	2.53			$	2.45

Productive Wells

     The following table presents our ownership at December 31, 2006 in productive oil and gas wells by region (a net well is our percentage ownership of a gross well).

		Oil Wells								Natural Gas Wells								Total Wells(1)
		Gross				Net				Gross				Net				Gross				Net
Permian Basin			3,375				1,753				363				139				3,738				1,892
Rocky Mountains			1,684				407				410				185				2,094				592
Mid-Continent			449				286				218				98				667				384
Gulf Coast			100				60				715				259				815				319
Michigan			89				67				1,034				405				1,123				472
Total			5,697				2,573				2,740				1,086				8,437				3,659

Drilling Activity

     We are engaged in numerous drilling activities on properties presently owned and intend to drill or develop other properties acquired in the future. The following table sets forth the results of our drilling activity for the last three years. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

		Gross Wells												Net Wells
		Productive				Dry				Total				Productive				Dry				Total
2006:
Development			401				14				415				300.6				9.0				309.6
Exploratory			17				5				22				10.2				2.3				12.5
Total			418				19				437				310.8				11.3				322.1
2005:
Development			276				18				294				164.7				10.6				175.3
Exploratory			7				7				14				1.3				3.9				5.2
Total			283				25				308				166.0				14.5				180.5
2004:
Development			157				7				164				73.4				3.7				77.1
Exploratory			3				2				5				1.5				0.2				1.7
Total			160				9				169				74.9				3.9				78.8

Item 3. Legal Proceedings

     In the ordinary course of business, we are a claimant or a defendant in various legal proceedings. In the opinion of our management, we do not have any litigation pending or threatened that is material.

Item 4. Submission of Matters to a Vote of Security Holders

     No matters were submitted to a vote of security holders during the fourth quarter of 2006.

EXECUTIVE OFFICERS OF THE REGISTRANT

     The following table sets forth certain information, as of February 15, 2007, regarding the executive officers of Whiting Petroleum Corporation:

Name		Age				Position
James J. Volker			60			Chairman, President and Chief Executive Officer
James T. Brown			54			Vice President, Operations
Bruce R. DeBoer			54			Vice President, General Counsel and Corporate Secretary
J. Douglas Lang			57			Vice President, Reservoir Engineering/Acquisitions
Patricia J. Miller			69			Vice President, Human Resources
David M. Seery			52			Vice President, Land
Michael J. Stevens			41			Vice President and Chief Financial Officer
Mark R. Williams			50			Vice President, Exploration and Development
Brent P. Jensen			37			Controller and Treasurer

     The following biographies describe the business experience of our executive officers:

     James J. Volker joined us in August 1983 as Vice President of Corporate Development and served in that position through April 1993. In March 1993, he became a contract consultant to us and served in that capacity until August 2000, at which time he became Executive Vice President and Chief Operating Officer. Mr. Volker was appointed President and Chief Executive Officer and a director in January 2002 and Chairman of the Board in January 2004. Mr. Volker was co-founder, Vice President and later President of Energy Management Corporation from 1971 through 1982. He has over thirty years of experience in the oil and gas industry. Mr. Volker has a degree in finance from the University of Denver, a MBA from the University of Colorado and has completed H. K. VanPoolen and Associates’ course of study in reservoir engineering.

     James T. Brown joined us in May 1993 as a consulting engineer. In March 1999, he became Operations Manager and, in January 2000, he became Vice President of Operations. Mr. Brown has over thirty years of oil and gas experience in the Rocky Mountains, Gulf Coast, California and Alaska. Mr. Brown is a graduate of the University of Wyoming, with a Bachelor’s Degree in civil engineering, and the University of Denver, with a MBA.

     Bruce R. DeBoer joined us as our Vice President, General Counsel and Corporate Secretary in January 2005. From January 1997 to May 2004, Mr. DeBoer served as Vice President, General Counsel and Corporate Secretary of Tom Brown, Inc., an independent oil and gas exploration and production company. Mr. DeBoer has over 20 years of experience in managing the legal departments of several independent oil and gas companies. He holds a Bachelor of Science Degree in Political Science from South Dakota State University and received his J.D. and MBA degrees from the University of South Dakota.

     J. Douglas Lang joined us in December 1999 as Senior Acquisition Engineer and became Manager of Acquisitions and Reservoir Engineering in January 2004 and Vice President—Reservoir Engineering/ Acquisitions in October 2004. His over thirty years of acquisition and reservoir engineering experience has included staff and managerial positions with Amoco, Petro-Lewis, General Atlantic Resources, UMC Petroleum and Ocean Energy. Mr. Lang holds a Bachelor’s Degree in Petroleum Engineering from the University of Wyoming and a MBA from the University of Denver. He is a registered Professional Engineer and has served on the national Board of Directors of the Society of Petroleum Evaluation Engineers.

     Patricia J. Miller joined us in April 1980 as Corporate Secretary and as Secretary to our President, becoming Director of Human Resources in May 1994. In November 2001, she was appointed Vice President of Human

Resources. She served as Corporate Secretary until January 2005. Mrs. Miller attended business school at Otero Junior College in LaJunta, Colorado and at Texas A & I in Kingsville, Texas.

     David M. Seery joined us as our Manager of Land in July 2004 as a result of our acquisition of Equity Oil Company, where he was Manager of Land and Manager of Equity’s Exploration Department, positions he had held for more than five years. He became our Vice President of Land in January 2005. Mr. Seery has twenty-five years of land experience including staff and managerial positions with Marathon Oil Company. Mr. Seery holds a Bachelor of Science Degree in Business Management from the University of Montana. He is a Registered Land Professional and held various duties with the Denver Association of Petroleum Landmen.

     Michael J. Stevens joined us in May 2001 as Controller, and became Treasurer in January 2002 and became Vice President and Chief Financial Officer in March 2005. From 1993 until May 2001, he served as Chief Financial Officer, Controller, Secretary and Treasurer at Inland Resources Inc., a company engaged in oil and gas exploration and development. He spent seven years in public accounting with Coopers & Lybrand in Minneapolis, Minnesota. He is a graduate of Mankato State University of Minnesota and is a Certified Public Accountant.

     Mark R. Williams joined us in December 1983 as Exploration Geologist, becoming Vice President of Exploration and Development in December 1999. He has twenty-four years of experience in the oil and gas industry and his areas of primary technical expertise are in sequence stratigraphy, seismic interpretation and petroleum economics. Mr. Williams is a graduate of the Colorado School of Mines with a Master’s Degree in geology and holds a Bachelor’s Degree in geology from the University of Utah.

     Brent P. Jensen joined us in August 2005 as Controller, and he became Controller and Treasurer in January 2006. He was previously with PricewaterhouseCoopers L.L.P. in Houston, Texas, where he held various positions in their oil and gas audit practice since 1994, which included assignments of four years in Moscow, Russia and three years in Milan, Italy. He has thirteen years of oil and gas accounting experience and is a Certified Public Accountant. Mr. Jensen holds a Bachelor of Arts degree with an emphasis in accounting and business from the University of California, Los Angeles.

     Executive officers are elected by, and serve at the discretion of, the Board of Directors. There are no family relationships between any of our directors or executive officers.

PART II

Item 5.		Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

     Whiting Petroleum Corporation’s common stock is traded on the New York Stock Exchange under the symbol “WLL.” The following table shows the high and low sale prices for our common stock for the periods presented.

		High				Low
Fiscal Year Ended December 31, 2006
Fourth Quarter (Ended December 31, 2006)		$	50.30			$	35.81
Third Quarter (Ended September 30, 2006)		$	48.10			$	37.30
Second Quarter (Ended June 30, 2006)		$	46.95			$	33.70
First Quarter (Ended March 31, 2006)		$	47.25			$	37.41
Fiscal Year Ended December 31, 2005
Fourth Quarter (Ended December 31, 2005)		$	44.91			$	36.77
Third Quarter (Ended September 30, 2005)		$	46.17			$	36.39
Second Quarter (Ended June 30, 2005)		$	43.20			$	28.19
First Quarter (Ended March 31, 2005)		$	46.30			$	27.76

     On February 15, 2007, there were 919 holders of record of our common stock.

     We have not paid any dividends since we were incorporated in July 2003. We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, the agreements governing our indebtedness prohibit us from paying dividends.

     Information relating to compensation plans under which our equity securities are authorized for issuance is set forth in Part III, Item 12 of this Annual Report on Form 10-K.

     The following information in this Item 5 of this Annual Report on Form 10-K is not deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 of the Securities Exchange Act of 1934, and will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent we specifically incorporate it by reference into such a filing.

     We completed our initial public offering in November 2003. Our common stock began trading on the New York Stock Exchange on November 20, 2003. The following graph compares on a cumulative basis changes since November 20, 2003 in (a) the total stockholder return on our common stock with (b) the total return on the Standard & Poor’s Composite 500 Index and (c) the total return on the Dow Jones US Oil Companies, Secondary Index. Such changes have been measured by dividing (a) the sum of (i) the amount of dividends for the measurement period, assuming dividend reinvestment, and (ii) the difference between the price per share at the end of and the beginning of the measurement period, by (b) the price per share at the beginning of the measurement period. The graph assumes $100 was invested on November 20, 2003 in our common stock, the Standard & Poor’s Composite 500 Index and the Dow Jones US Oil Companies, Secondary Index.

		11/20/03				12/31/03				12/31/04				12/31/05				12/31/06
Whiting Petroleum Corporation		$	100			$	113			$	186			$	246			$	286
Standard & Poor’s Composite 500 Index			100				108				117				121				137
Dow Jones US Oil Companies, Secondary Index			100				114				160				263				275

Item 6. Selected Financial Data

     The consolidated income statement information for the years ended December 31, 2006, 2005 and 2004 and the consolidated balance sheet information at December 31, 2006 and 2005 are derived from our audited financial statements included elsewhere in this report. The consolidated income statement information for the years ended December 31, 2003 and 2002 and the consolidated balance sheet information at December 31, 2004, 2003 and 2002 are derived from audited financial statements that are not included in this report. Our historical results include the results from our recent acquisitions beginning on the following dates: Utah Hingeline, August 29, 2006; Michigan Properties, August 15, 2006; North Ward Estes and Ancillary Properties, October 4, 2005; Postle Properties, August 4, 2005; Limited Partnership Interests, June 23, 2005; and Green River Basin, March 31, 2005.

		Year Ended December 31,
		2006				2005				2004				2003				2002
		(dollars in millions except per share data)
Consolidated Income Statement Information:
Revenues and other income:
Oil and natural gas sales		$	773.1			$	573.2			$	281.1			$	175.7			$	122.7
Loss on oil and natural gas hedging activities			(7.5	)			(33.4	)			(4.9	)			(8.7	)			(3.2	)
Gain on sale of oil and gas properties			12.1				—				1.0				—				1.0
Gain on sale of marketable securities			—				—				4.8				—				—
Interest income and other			1.1				0.6				0.1				0.3				—
Total revenues and other income			778.8				540.4				282.1				167.3				120.5
Costs and expenses:
Lease operating			183.6				111.6				54.2				43.2				32.9
Production taxes			47.1				36.1				16.8				10.7				7.4
Depreciation, depletion and amortization			162.8				97.6				54.0				41.2				43.6
Exploration and impairment			34.5				16.7				6.3				3.2				1.8
General and administrative			37.8				30.6				19.2				13.0				10.3
Change in Production Participation Plan liability			6.2				9.7				1.7				(0.2	)			1.7
Phantom equity plan (1)			—				—				—				10.9				—
Interest expense			73.5				42.0				15.9				9.2				10.9
Total costs and expenses			545.5				344.3				168.1				131.2				108.6
Income before income taxes and cumulative change in accounting principle			233.3				196.1				114.0				36.1				11.9
Income tax expense (2)			76.9				74.2				44.0				13.9				4.2
Income before cumulative change in accounting principle			156.4				121.9				70.0				22.2				7.7
Cumulative change in accounting principle (3)			—				—				—				(3.9	)			—
Net income		$	156.4			$	121.9			$	70.0			$	18.3			$	7.7
Income per common share before cumulative change in accounting principle, basic		$	4.26			$	3.89			$	3.38			$	1.18			$	0.41
Income per common share before cumulative change in accounting principle, diluted		$	4.25			$	3.88			$	3.38			$	1.18			$	0.41
Net income per common share, basic		$	4.26			$	3.89			$	3.38			$	0.98			$	0.41
Net income per common share, diluted		$	4.25			$	3.88			$	3.38			$	0.98			$	0.41
Other Financial Information:
Net cash provided by operating activities		$	411.2			$	330.2			$	134.1			$	91.9			$	62.6
Net cash used in investing activities		$	527.6			$	1,126.9			$	524.4			$	47.6			$	157.5
Net cash provided by financing activities		$	116.4			$	805.5			$	338.4			$	4.4			$	98.7
Ratio of earnings to fixed charges (4)			4.14x				5.64x				8.01x				4.85x				2.08x
Capital expenditures		$	552.0			$	1,126.9			$	530.6			$	47.6			$	165.4

		As of December 31,
		2006				2005				2004				2003				2002
		(dollars in millions)
Consolidated Balance Sheet Information:
Total assets		$	2,585.4			$	2,235.2			$	1,092.2			$	536.3			$	448.5
Total debt		$	995.4			$	875.1			$	328.4			$	188.0			$	265.5
Stockholders’ equity		$	1,186.7			$	997.9			$	612.4			$	259.6			$	122.8

Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward Looking Statements

     This report 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. Some, but not all, of the risks and uncertainties include: declines in oil or gas prices; our level of success in exploitation, exploration, development and production activities; the timing of our exploration and development expenditures, including our ability to obtain drilling rigs; our ability to obtain external capital to finance acquisitions; our ability to identify and complete acquisitions and to successfully integrate acquired businesses, including our ability to realize cost savings from completed acquisitions; unforeseen underperformance of or liabilities associated with acquired properties; inaccuracies of our reserve estimates or our assumptions underlying them; 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; risks related to our level of indebtedness and periodic redeterminations of our borrowing base under our credit agreement; our ability to replace our oil and gas reserves; any loss of our senior management or technical personnel; competition in the oil and gas industry; risks arising out of our hedging transactions and other risks described under the caption “Risk Factors” in this Annual Report on Form 10-K. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this report.

Overview

     We are engaged in oil and gas acquisition, development, exploitation, production and exploration activities primarily in the Permian Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the United States. Over the last six years, we have emphasized the acquisition of properties that provided current production and upside potential through further development. Our drilling activity is directed at this development, specifically on projects that we believe provide repeatable successes in particular fields. Our combination of acquisitions and development allows us to direct our capital resources to what we believe to be the most advantageous investments.

     We have historically acquired operated and non-operated properties that meet or exceed our rate of return criteria. For acquisitions of properties with additional development, exploitation and exploration potential, our focus has been on acquiring operated properties so that we can better control the timing and implementation of capital spending. In some instances, we have been able to acquire non-operated property interests at attractive rates of return that provided a foothold in a new area of interest or that have complemented our existing operations. We intend to continue to acquire both operated and non-operated interests to the extent we believe they meet our return criteria. In addition, our willingness to acquire non-operated properties in new geographic regions provides us with geophysical and geologic data in some cases that leads to further acquisitions in the same region, whether on an operated or non-operated basis. We sell properties when we believe that the sale price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own.

     Our revenue, profitability and future growth rate depend on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and gas reserves that we can economically produce and our access to capital.

     Although independent engineers estimated probable and possible reserves relating to certain 2006, 2005 and prior year producing property acquisitions, we, consistent with our present acquisition practices, have associated all acquisition costs with proved reserves. Because of our substantial recent acquisition activity, our discussion and analysis of our historical financial condition and results of operations for the periods discussed below may not necessarily be comparable with or applicable to our future results of operations. Our historical results include the results from our recent acquisitions beginning on the following dates: Utah Hingeline, August 29, 2006; Michigan Properties, August 15, 2006; North Ward Estes and Ancillary Properties, October 4, 2005; Postle Properties, August 4, 2005; Limited Partnership Interests, June 23, 2005; and Green River Basin, March 31, 2005.

2006 Acquisitions

     Utah Hingeline. On August 29, 2006, we acquired a 15% working interest in approximately 170,000 acres of unproved properties in the central Utah Hingeline play for $25.0 million. No producing properties or proved reserves were associated with this acquisition. As part of this transaction, the operator will pay 100% of our drilling and completion costs for the first three wells in the project.

     Michigan Properties. On August 15, 2006, we acquired 65 producing properties, a gathering line, gas processing plant and 30,437 net acres of leasehold held by production in Michigan. The purchase price was $26.0 million for estimated proved reserves of 1.4 MMBOE as of the acquisition effective date of May 1, 2006, resulting in a cost of $18.55 per BOE of estimated proved reserves. Proved developed reserve quantities represented 99% of the total proved reserves acquired. The average daily production from the properties was 0.6 MBOE/d as of the acquisition effective date. We operate 85% of the acquired properties.

     Oil Pipeline and Gathering System. On June 1, 2006, we acquired the Postle field oil gathering system and oil transportation line extending 13 miles from the eastern side of the Postle field to a connection point with an interstate oil pipeline in Hooker, Oklahoma. We purchased the oil gathering system and pipeline for $5.3 million.

     We funded our 2006 acquisitions with cash on hand and borrowings under Whiting Oil and Gas Corporation’s credit agreement.

2006 Divestitures

     During 2006, we sold our interests in several non-core properties for an aggregate amount of $24.4 million in cash for total estimated proved reserves of 1.4 MMBOE as of the divestitures’ effective dates. The divested properties included interests in the Cessford field in Alberta, Canada; Permian Basin of West Texas and New Mexico; and the Ashley Valley field in Uintah County, Utah. The average net production from the divested property interests was 0.4 MBOE/d as of the dates of disposition, and we recognized a pre-tax gain on sale of $12.1 million related to these divestitures.

2005 Acquisitions

     North Ward Estes and Ancillary Properties. On October 4, 2005, we acquired the operated interest in the North Ward Estes field in Ward and Winkler counties, Texas, and certain smaller fields located in the Permian Basin. The purchase price was $459.2 million, consisting of $442.0 million in cash and 441,500 shares of our common stock, for estimated proved reserves of 82.1 MMBOE as of the acquisition effective date of July 1, 2005, resulting in a cost of $5.58 per BOE of estimated proved reserves. Proved developed reserve quantities represented 36% of the total proved reserves acquired. The average daily production from the properties was 4.6 MBOE/d as of the acquisition effective date. We funded the cash portion of the purchase price with the net proceeds from a public offering of common stock and a private placement of 7% Senior Subordinated Notes due 2014. We expect to incur $656.0 million in future development costs related to these properties.

     Postle Properties. On August 4, 2005, we acquired the operated interest in producing oil and gas fields located in the Oklahoma Panhandle. The purchase price was $343.0 million for estimated proved reserves of 40.3 MMBOE as of the acquisition effective date of July 1, 2005, resulting in a cost of $8.52 per BOE of estimated proved reserves. The average daily production from the properties was 4.2 MBOE/d as of the acquisition effective date. Proved developed reserve quantities represented 57% of the total proved reserves acquired. We funded the acquisition through borrowings under Whiting Oil and Gas Corporation’s credit agreement. We expect to incur $302.6 million in future development costs related to these properties.

     Limited Partnership Interests. On June 23, 2005, we acquired all of the limited partnership interests in three institutional partnerships managed by our wholly-owned subsidiary Whiting Programs, Inc. The partnership properties were located in Louisiana, Texas, Arkansas, Oklahoma and Wyoming. The purchase price was $30.5 million for estimated proved reserves of 2.9 MMBOE as of the acquisition effective date of January 1, 2005, resulting in a cost of $10.52 per BOE of estimated proved reserves. Proved developed reserve quantities represented 99% of the total proved reserves acquired. The average daily production from the properties was 0.7 MBOE/d as of the acquisition effective date. We funded the acquisition with cash on hand.

     Green River Basin. On March 31, 2005, we acquired operated interests in five producing gas fields in the Green River Basin of Wyoming. The purchase price was $65.0 million for estimated proved reserves of 8.4 MMBOE as of the acquisition effective date of March 1, 2005, resulting in a cost of $7.74 per BOE of estimated proved reserves. Proved developed reserve quantities represented 68% of the total proved reserves acquired. The average daily production from the properties was 1.1 MBOE/d as of the acquisition effective date. We funded the acquisition though borrowings under Whiting Oil and Gas Corporation’s credit agreement and with cash on hand.

Results of Operations

     The following table sets forth selected operating data for the periods indicated:

		Year Ended December 31,
		2006				2005				2004
Net production:
Oil (MMbbls)			9.8				7.0				3.7
Natural gas (Bcf)			32.1				30.3				25.1
Total production (MMBOE)			15.2				12.1				7.9
Net sales (in millions):
Oil (1)		$	561.2			$	360.4			$	141.7
Natural gas (1)		$	211.9			$	212.8			$	139.4
Total oil and natural gas sales		$	773.1			$	573.2			$	281.1
Average sales prices:
Oil (per Bbl)		$	57.27			$	51.26			$	38.72
Effect of oil hedges on average price (per Bbl)		$	(0.95	)		$	(2.72	)		$	(1.33	)
Oil net of hedging (per Bbl)		$	56.32			$	48.54			$	37.39
Average NYMEX price		$	66.25			$	56.61			$	41.43
Natural gas (per Mcf)		$	6.59			$	7.03			$	5.56
Effect of natural gas hedges on average price (per Mcf)		$	0.06			$	(0.47	)		$	—
Natural gas net of hedging (per Mcf)		$	6.65			$	6.56			$	5.56
Average NYMEX price		$	7.23			$	8.64			$	6.14
Cost and expense (per BOE):
Lease operating expenses		$	12.12			$	9.24			$	6.91
Production taxes		$	3.11			$	2.99			$	2.14
Depreciation, depletion and amortization expense		$	10.74			$	8.08			$	6.89
General and administrative expenses		$	2.49			$	2.53			$	2.45

     Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

     Oil and Natural Gas Sales. Our oil and natural gas sales revenue increased $199.9 million to $773.1 million in 2006 compared to 2005. Sales are a function of sales volumes and average sales prices. Our oil sales volumes increased 39% and our gas sales volumes increased 6% between periods. The volume increases resulted from acquisitions completed in 2005 and 2006 and successful drilling activities over the past year, which produced new sales volumes that more than offset natural production decline. Our average price for oil increased 12% and our average price for natural gas decreased 6% between periods.

     Loss on Oil and Natural Gas Hedging Activities. We hedged 54% of our oil volumes during 2006, incurring a hedging loss of $9.4 million, and 58% of our oil volumes during 2005, incurring a hedging loss of $19.1 million. We hedged 59% of our gas volumes during 2006 incurring a hedging gain of $1.9 million, and 60% of our gas volumes during 2005, incurring a hedging loss of $14.3 million. See Item 7A, “Qualitative and Quantitative Disclosures About Market Risk” for a list of our outstanding oil and gas hedges as of January 1, 2007.

     Gain on Sale of Oil and Gas Properties. During 2006, we sold our interests in several non-core properties for an aggregate amount of $24.4 million in cash and recognized a pre-tax gain on sale of $12.1 million. The divested properties included interests in the Cessford field in Alberta, Canada; Permian Basin of West Texas and New Mexico; and the Ashley Valley field in Uintah County, Utah.

     Lease Operating Expenses. Our lease operating expense increased $72.1 million to $183.6 million in 2006 compared to 2005. The increase resulted primarily from costs associated with new property acquisitions during 2005 and 2006 and successful drilling activities over the past year. Our lease operating expense as a percentage of oil and gas sales increased from 19% during 2005 to 24% during 2006. Our lease operating expenses per BOE increased from $9.24 during 2005 to $12.12 during 2006. The increase of 31% on a BOE basis was primarily caused by inflation in the cost of oil field goods and services, a high level of workover activity on recently acquired properties, increased costs related to tertiary recovery projects, a change in labor billing practices and higher energy costs. Oil field goods and services increased due to a higher demand in the industry. Workovers amounted to $8.9 million in 2006, as compared to $3.9 million of workover activity during 2005. During the fourth quarter of 2006, we revised our labor billing practices to better conform to COPAS guidelines. The changes resulted in lower general and administrative expense to us and higher amounts of lease operating expense being charged to us and our joint interest owners on properties we operate.

     Production Taxes. The production taxes we pay are generally calculated as a percentage of oil and gas sales revenue before the effects of hedging. We take full advantage of all credits and exemptions allowed in our various taxing jurisdictions. Our production taxes for 2006 and 2005 were 6.1% and 6.3%, respectively, of oil and gas sales. The 2006 rate was lower than the 2005 rate due to the change in property mix associated with recent acquisitions.

     Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) increased $65.2 million to $162.8 million during 2006 as compared to $97.6 million for 2005. The increase resulted from higher production volumes in 2006 and an increase in our DD&A rate. On a BOE basis, our DD&A rate increased from $8.08 during 2005 to $10.74 in 2006. The primary factors causing this rate increase were higher drilling expenditures, downward oil and gas reserve revisions, and an increased level of expenditures to develop proved undeveloped reserves, particularly related to the enhanced oil recovery projects in the Postle and North Ward Estes fields where the development of undeveloped reserves does not increase existing proved reserves. Under the successful efforts method of accounting, costs to develop proved undeveloped reserves are added into the DD&A rate when incurred. Also contributing to our higher DD&A rate was the association of all 2005 property acquisition costs with proved reserves and none with unproved reserves, thereby including all such costs in our DD&A rate immediately when incurred. Changes to the pricing environment can also positively impact our DD&A rate. Price increases allow for longer economic production lives and corresponding increased reserve volumes and, as a result, lower depletion rates. Price decreases have the opposite effect. The components of our DD&A expense were as follows (in thousands):

		Year Ended December 31,
		2006				2005
Depletion and amortization		$	157,868			$	93,818
Depreciation			2,675				1,457
Accretion of asset retirement obligations			2,288				2,364
Total		$	162,831			$	97,639

     Exploration and Impairment Costs. Our exploration and impairment costs increased $17.8 million to $34.5 million in 2006 compared to 2005. The components of our exploration and impairment costs were as follows (in thousands):

		Year Ended December 31,
		2006				2005
Exploration		$	30,079			$	14,665
Impairment			4,455				2,034
Total		$	34,534			$	16,699

     Higher exploration costs resulted from three exploratory dry holes drilled in the Rocky Mountains region, one exploratory dry hole drilled in the Gulf Coast region and one exploratory dry hole drilled in the Mid-Continent region in 2006, totaling $7.2 million. In 2005, we drilled a total of seven exploratory dry holes, totaling $4.0 million. We incurred $12.2 million in geological and geophysical expenses during 2006, up $7.4 million from 2005. We also hired additional exploration personnel to support the increased drilling budget from $223.6 million in 2005 to $455.0 million in 2006 resulting in an additional $4.0 million of exploration expense. The impairment charge in 2006 related to $3.7 million of amortized leasehold costs associated with individually insignificant unproved properties and $0.8 million of proved properties. The impairment charge in 2005 related to unrecoverable costs associated with our investment in the Cherokee Basin in Kansas.

     General and Administrative Expenses. We report general and administrative expenses net of reimbursements. The components of our general and administrative expenses were as follows (in thousands):

		Year Ended December 31,
		2006				2005
General and administrative expenses		$	60,972			$	42,594
Reimbursements and allocations			(23,164	)			(11,987	)
General and administrative expenses, net		$	37,808			$	30,607

     General and administrative expenses before reimbursements and allocations increased $18.4 million to $61.0 million during 2006. The largest components of the increase related to higher costs for personnel salaries, benefits and related taxes of $13.6 million and an increase in the current year accrual for cash payments under our Production Participation Plan of $3.6 million. Personnel salary expenses were higher in 2006 due to an increase in our employee base resulting from our continued growth. The increased cost of the Production Participation Plan was caused primarily by higher 2006 production volumes and higher average sales prices on crude oil between years. The increase in reimbursements and allocations in 2006 was caused by increased salary expenses and a higher number of field workers and operated properties, due to recent acquisitions and drilling activities during 2006. In addition, during the fourth quarter of 2006, we revised our labor billing practices to better conform to COPAS guidelines. The changes resulted in lower general and administrative expense to us and higher amounts of lease operating expense being allocated to us and charged to our joint interest owners on properties we operate. As a percentage of oil and gas sales, our general and administrative expenses remained consistent at 5%.

     Change in Production Participation Plan Liability. For the year ended December 31, 2006, this non-cash expense decreased $3.6 million to $6.2 million. This expense represents the change in the vested present value of estimated future payments to be made to participants after 2007 under our Production Participation Plan (“Plan”). Although payments take place over the life of oil and gas properties contributed to the Plan, which for some properties is over 20 years, we must expense the present value of estimated future payments over the Plan’s five year vesting period. The 2006 expense primarily reflects changes to future cash flow estimates and related Plan liability, due to the effect of a sustained higher price environment and recent acquisitions, as well as employees’ continued vesting in the Plan. Assumptions that are used to calculate this liability are subject to estimation and will vary from year to year based on the current market for oil and gas, discount rates and overall market conditions.

     Interest Expense. The components of our interest expense were as follows (in thousands):

		Year Ended December 31,
		2006				2005
Credit Agreement		$	21,478			$	9,997
Senior Subordinated Notes			44,530				25,109
Amortization of debt issue costs and debt discount			5,208				4,076
Accretion of tax sharing liability			2,016				2,725
Other			813				138
Capitalized interest			(556	)			—
Total interest expense		$	73,489			$	42,045

     The increase in interest expense and amortization of debt issue costs and debt discount were mainly due to the April 2005 issuance of $220.0 million 7.25% Senior Subordinated Notes due 2013, the October 2005 issuance of $250.0 million 7% Senior Subordinated Notes due 2014, and additional borrowings outstanding in 2006 under our credit agreement. We also experienced higher weighted average interest rates on our debt during 2007.

     Our weighted average debt outstanding during 2006 was $945.3 million versus $553.0 million during 2005. Our weighted average effective cash interest rate was 7.0% during 2006 versus 6.4% during 2005. After inclusion of non-cash interest costs related to the amortization of debt issue costs and debt discounts and the accretion of the tax sharing liability, our weighted average effective all-in interest rate was 7.5% during 2006 versus 7.2% during 2005.

     Income Tax Expense. Income tax expense totaled $76.9 million for 2006 and $74.2 million for 2005. Our effective income tax rate decreased from 37.8% for 2005 to 33.0% for 2006 primarily due to the recognition in 2006 of a $4.2 million deferred tax benefit for 2005 enhanced oil recovery (“EOR”) tax credits, a $3.3 million benefit relating to an adjustment of our effective rate to our 2005 state returns as filed, and deferred tax benefits of $1.3 million as a result of recently enacted state tax legislation.

     EOR credits are a credit against federal income taxes for certain costs related to extracting high-cost oil, utilizing certain prescribed “enhanced” tertiary recovery methods. Federal EOR credits are subject to phase-out according to the level of average domestic crude prices. Due to recent high oil prices, the EOR credit was phased-out for 2006.

     The current portion of income tax expense was $12.3 million for 2006 compared to $8.5 million in 2005. In 2006, we reported a tax loss on our 2005 federal return as filed, primarily due to intangible drilling deductions allowed, which resulted in a federal tax refund of $4.7 million.

     Net Income. Net income increased from $121.9 million in 2005 to $156.4 million for 2006. The primary reasons for this increase included a 26% increase in equivalent volumes sold, a 14% increase in oil and gas prices net of hedging between periods, certain income tax benefits recognized during 2006 and a gain on sale of oil and gas properties. These increases were partially offset by higher lease operating expenses, production taxes, DD&A, exploration and impairment, general and administrative and interest expenses in 2006 resulting from our continued growth.

     Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

     Oil and Natural Gas Sales. Our oil and natural gas sales revenue increased $292.2 million to $573.2 million in 2005. Sales are a function of sales volumes and average sales prices. Our sales volumes increased 54% between periods on a BOE basis. The volume increase resulted primarily from acquisition activities and successful drilling activities over the past year that produced new sales volumes that more than offset natural field production decline.

Our production volumes for 2005 were slightly less than anticipated due in part to delays in rig availability that caused delays in our development drilling program and temporary pipeline shut downs and workover activity in the first quarter of 2005. Hurricanes Katrina and Rita caused only minor reductions to our 2005 sales volumes, in that only 16,700 BOE of total estimated production was lost during 2005 due to the hurricanes. Our average price for crude oil increased 32% between periods and our average price for natural gas sales increased 26%.

     Loss on Oil and Natural Gas Hedging Activities. We hedged 58% of our oil volumes during 2005, incurring a hedging loss of $19.1 million, and 50% of our oil volumes during 2004, incurring a hedging loss of $4.9 million. We hedged 60% of our gas volumes during 2005, incurring a hedging loss of $14.3 million, and 32% of our gas volumes during 2004, incurring no hedging gain or loss.

     Gain on Sale of Marketable Securities. During 2004, we sold all of our holdings in Delta Petroleum, Inc., which trades publicly under the symbol “DPTR”. We realized gross proceeds of $5.4 million and recognized a gain on sale of $4.8 million. During 2005, we had no investments in marketable securities.

     Gain on Sale of Oil and Gas Properties. During 2004, we sold certain undeveloped acreage in Wyoming. No value had been assigned to the acreage when we acquired it over five years ago. As a result, the recognized gain on sale was equal to the gross proceeds of $1.0 million.

     Lease Operating Expenses. Our lease operating expense increased $57.3 million to $111.6 million in 2005 compared to 2004. The increase resulted primarily from costs associated with new property acquisitions over the past year. Our lease operating expenses per BOE increased from $6.91 during 2004 to $9.24 during 2005. The increase of 34% was mainly caused by higher costs for electric power and increases in the cost of oil field goods and services due to higher demand in the industry. In addition, our lease operating expenses increased on a BOE basis due to the newly acquired Postle and North Ward Estes properties, which had fourth quarter combined operating costs of $12.72 per BOE relating to the secondary and tertiary recovery projects underway on those fields.

     Production Taxes. The production taxes we pay are generally calculated as a percentage of oil and gas sales revenue before the effects of hedging. We take full advantage of all credits and exemptions allowed by the various taxing jurisdictions. Our production taxes for 2005 and 2004 were 6.3% and 6.0%, respectively, of oil and gas sales. The increase in tax rates between periods was related to product price increases that eliminate certain exemptions and move us into higher tax tiers in our various tax jurisdictions, which effect was partially offset by lower production taxes on our properties newly acquired in 2005.

     Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) increased $43.6 million to $97.6 million during 2005 as compared to $54.0 million for 2004. The increase resulted from increased production due to our recent acquisitions and an increase in our DD&A rate. On a BOE basis, our DD&A rate increased from $6.89 during 2004 to $8.08 in 2005. The primary factors causing this rate increase were higher drilling expenditures, downward oil and gas reserve revisions, and an increased level of expenditures to develop proved undeveloped reserves, particularly related to the enhanced oil recovery projects in the Postle and North Ward Estes fields where the development of undeveloped reserves does not increase existing proved reserves. Under the successful efforts method of accounting, costs to develop proved undeveloped reserves are added into the DD&A rate when incurred. Changes to the pricing environment can also positively impact our DD&A rate. Price increases allow for longer economic production lives and corresponding increased reserve volumes and, as a result, lower depletion rates. Price decreases have the opposite effect. The components of our DD&A expense were as follows (in thousands):

		Year Ended December 31,
		2005				2004
Depletion		$	93,818			$	51,424
Depreciation			1,457				832
Accretion of asset retirement obligations			2,364				1,754
Total		$	97,639			$	54,010

     Exploration and Impairment Costs. Our exploration and impairment costs increased $10.4 million to $16.7 million in 2005 compared to 2004. The components of our exploration and impairment costs were as follows (in thousands):

		Year Ended December 31,
		2005				2004
Exploration		$	14,665			$	4,177
Impairment			2,034				2,152
Total		$	16,699			$	6,329

     Higher exploratory costs resulted from seven exploratory dry holes drilled during 2005 totaling $4.0 million, as compared to two exploratory dry holes in 2004 totaling $0.6 million. We also hired additional geological and geophysical personnel to support the increased drilling budget from $83.8 million in 2004 to $223.6 million in 2005. The impairment charge in 2005 relates primarily to unrecoverable costs associated with our investment in the Cherokee Basin in Kansas. The impairment charge in 2004 was for the write down of cost associated with the High Island field located off the coast of Texas.

     General and Administrative Expenses. We report general and administrative expenses net of reimbursements. The components of our general and administrative expenses were as follows (in thousands):

		Year Ended December 31,
		2005				2004
General and administrative expenses		$	42,594			$	25,992
Reimbursements			(11,987	)			(6,768	)
General and administrative expenses, net		$	30,607			$	19,224