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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

or

Commission file number: 001-31899

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

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

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

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     X         No          

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.  [X]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).      Yes     X         No          

Aggregate market value of the voting stock held by nonaffiliates of the registrant at June 30, 2004:  $466,391,785.75

Number of shares of the registrant's common stock outstanding at February 15, 2005:  29,720,103 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2005 Annual Meeting of Stockholders are incorporated by reference into Part III.

TABLE OF CONTENTS

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 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.

        “Bcfe” One billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

        “Bopd” Barrels of oil per day.

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

        “horizontal re-entry well” A new well in which a pre-existing wellbore is used as the starting point of a new horizontal borehole. Drilling a horizontal re-entry well typically involves milling a hole in the casing of the pre-existing wellbore and drilling hundreds or thousands of feet from the pre-existing wellbore.

        “Mcf” One thousand cubic feet of natural gas.

        "Mcf/d" One Mcf per day.

        “Mcfe” One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

        "Mcfe/d" One Mcfe per day.

        “MMbbls” millions of barrels of oil or other liquid hydrocarbons.

        "MMbtu" One million British Thermal Units.

        “MMcf” One million cubic feet of natural gas.

        "MMcf/d" One MMcf per day.

        “MMcfe” One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

        "MMcfe/d" One MMcfe per day.

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        “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 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%.

        “reservoir” A porous and permeable underground formation containing a natural accumulation of producible 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 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 a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.

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PART I

Item 1.  Business

Overview

        We are engaged in oil and natural gas exploitation, acquisition, exploration and production activities primarily in the Rocky Mountains, Permian Basin, Gulf Coast, Michigan, Mid-Continent and California regions of the United States. Our focus is on pursuing growth projects that we believe will generate attractive rates of return and maintaining a balanced portfolio of lower risk, long-lived oil and natural gas properties that provide stable cash flows.

        Since our inception in 1980, we have built a strong asset base and achieved steady growth through both property acquisitions and exploitation activities. As of January 1, 2005, our estimated proved reserves totaled 865.4 Bcfe, of which 70.1% were classified as proved developed. These estimated reserves had a pre-tax PV10% value of approximately $1.85 billion, of which approximately 70% came from properties located in three states: Texas, North Dakota and Michigan. During 2004, we invested $606.9 million in acquisition, exploration and development activities, including $79.4 million for the drilling of 169 gross (79 net) wells. Of these new wells, 160 resulted in productive completions and 9 were unsuccessful, yielding a 95% success rate. We have budgeted approximately $130 million to $150 million for development drilling expenditures in 2005. Although we have no specific budget for acquisitions, we will also seek property acquisition opportunities that meet our rate of return criteria and complement our existing core properties.

        As of January 1, 2005, we had a balanced portfolio of oil and natural gas reserves, with approximately 39.3% of our proved reserves consisting of natural gas and approximately 60.7% consisting of oil. Our properties generally have long reserve lives and reasonably stable and predictable well production characteristics with a ratio of proved reserves to annual production (based on December 2004 production) of approximately 12.6 years.

        The following table summarizes our estimated proved reserves and pre-tax PV10% value within our core areas as of January 1, 2005 and our estimated December 2004 average daily production.

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2004 Acquisitions

        During 2004, we completed seven separate acquisitions of producing properties with a combined purchase price of $535.1 million for estimated proved reserves as of the effective dates of the acquisitions of approximately 436.1 Bcfe, representing an average cost of approximately $1.23 per Mcfe of estimated proved reserves. We will continue to seek property acquisition opportunities that complement our existing core properties. We believe that our exploitation and acquisition expertise and our drilling inventory, together with our operating experience and efficient cost structure, provide us with the potential to continue our growth. The following table summarizes certain information about the purchase price, estimated proved reserves and pre-tax PV10% value as of the effective dates of acquisition for each of the seven acquisitions that we completed in 2004.

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Permian Basin Properties

        On September 23, 2004, we acquired interests in seventeen fields in the Permian Basin of West Texas and Southeast New Mexico, including interests in key fields such as Parkway Field in Eddy County, New Mexico; Would Have and Signal Peak Fields in Howard County, Texas; Keystone Field in Winkler County, Texas; and the DEB Field in Gaines County, Texas. The purchase price was $345.0 million in cash and was funded through borrowings under our bank credit agreement. Based on the purchase price and estimated proved reserves of 251.1 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.37 per Mcfe of estimated proved reserves.

Equity Oil Company

        We acquired 100% of the outstanding stock of Equity Oil Company on July 20, 2004. In the merger, we issued approximately 2.2 million shares of our common stock to Equity’s shareholders and repaid all of Equity’s outstanding debt of $29.0 million under its credit facility. Equity’s operations are focused primarily in California, Colorado, North Dakota and Wyoming. Based on the purchase price of $72.6 million and estimated proved reserves of 87.7 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $0.83 per Mcfe of estimated proved reserves.

Other Cash Acquisitions of Properties

        Colorado and Wyoming Properties. On August 13, 2004, we acquired interests in four producing oil and gas fields in Colorado and Wyoming. The purchase price was $44.2 million in cash and was funded under our bank credit agreement. Based on the purchase price of $44.2 million and estimated proved reserves of 39.8 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.11 per Mcfe of estimated proved reserves.

        Wyoming and Utah Properties. On September 30, 2004, we acquired interests in three operated fields in Wyoming and Utah. The purchase price was $35.0 million in cash and was funded under our bank credit agreement. Based on the purchase price of $35.0 million and estimated proved reserves of 30.8 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.14 per Mcfe of estimated proved reserves.

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        Louisiana and South Texas Properties. On August 16, 2004, we acquired interests in five fields in Louisiana and South Texas. The purchase price was $19.3 million in cash and was funded under our bank credit agreement. Based on the purchase price of $19.3 million and estimated proved reserves of 12.0 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.61 per Mcfe of estimated proved reserves.

        Mississippi Properties. On November 3, 2004, we acquired an interest in the Lake Como Field in Mississippi. The purchase price was $12.0 million in cash and was funded under our bank credit agreement. Based on the purchase price of $12.0 million and estimated proved reserves of 10.6 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.43 per Mcfe of estimated proved reserves.

        Additional Permian Basin Interest. On December 31, 2004, we acquired an additional working interest in the Would Have Field in Texas. The purchase price was $7.0 million in cash and was funded under our bank credit agreement. Based on the purchase price and estimated proved reserves of 4.1 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.72 per Mcfe of estimated proved reserves.

Business Strategy

        Our goal is to increase stockholder value by investing in oil and gas projects with attractive rates of return on capital employed. We plan to achieve this goal by exploiting and developing our existing oil and natural gas properties and pursuing acquisitions of additional properties. Specifically, we have focused, and plan to continue to focus, on the following:

        Developing and Exploiting Existing Properties. We believe that there is significant value to be created by drilling the numerous identified undeveloped opportunities on our properties. As of January 1, 2005, we owned interests in a total of 752,000 gross (300,400 net) developed acres. In addition, as of December 31, 2004, we owned interests in approximately 608,800 gross (315,700 net) undeveloped acres that contain many exploitation opportunities. During the year ending December 31, 2004, we invested $79.4 million to drill 169 gross (79 net) wells. Of these new wells, 95% resulted in productive completions. For 2005, we have budgeted $130 million to $150 million for the further exploration and development of our properties.

        Pursuing Profitable Acquisitions. We have pursued and intend to continue to pursue acquisitions of properties that we believe to have exploitation and development potential comparable to our existing inventory of drilling locations. We have developed and refined an acquisition program designed to increase reserves and complement our existing core properties. We have an experienced team of management, engineering and geoscience professionals who identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties. During 2004, we completed seven separate acquisitions of producing properties with a combined purchase price of $535.1 million for estimated proved reserves as of the effective dates of the acquisitions of approximately 436.1 Bcfe, resulting in an aggregate cost of $1.23 per Mcfe of estimated proved reserves. To secure attractive realized commodity prices on a portion of our producing volumes, we periodically enter into derivative contracts, typically no-cost collars.

        Focusing on High Return Operated and Non-Operated Properties. We have historically acquired operated as well as 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 complemented our existing operations. We intend to continue to acquire both operated and non-operated interests to the extent they meet our return criteria and further our growth strategy.

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Competitive Strengths

        We believe that our key competitive strengths lie in our diversified asset base, our experienced management and technical team and our commitment to efficient utilization of new technologies.

        Diversified Asset Base. As of January 1, 2005, we had interests in 6,970 productive wells across our six core geographical areas. This property base, as well as our continuing business strategy of acquiring and developing properties in our core operating areas, presents us with a large number of opportunities for successful development and exploitation and additional acquisitions.

        Experienced Management Team. Our management team averages over 25 years of experience in the oil and natural 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 20 years of experience in the evaluation, acquisition and operational assimilation of oil and natural 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 961 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, such as the WellView® software system, 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 development activities.

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Proved Reserves

        Our estimated proved reserves as of January 1, 2005 are summarized in the table below.

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Marketing and Major Customers

        We principally sell our oil and natural 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 natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For fiscal year 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 interferes 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 natural 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 natural 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 natural 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 natural gas industry.

Regulation

Regulation of Transportation and Sale of Natural Gas

        Historically, the transportation and sale for resale of natural gas in inter state commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the Federal Energy Regulatory Commission, or the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act. The Decontrol Act removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

        Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued Order No. 636 and a series of related orders to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

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        In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised the FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect. While most major aspects of Order No. 637 have been upheld on judicial review, certain issues such as capacity segmentation and right of first refusal are pending further consideration by the FERC. We cannot predict what action FERC will take on these matters in the future, or whether the FERC’s actions will survive further judicial review.

        The Outer Continental Shelf Lands Act, which the FERC implements as to transportation and pipeline issues, 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. Additional proposals and proceedings that might affect the natural gas industry are pending before the FERC and the courts. 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 transportation rates for oil 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. On remand, 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.

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        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 natural 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 natural gas properties, the establishment of maximum allowable rates of production from oil and natural 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 natural 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, natural 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 natural gas leases through regulations issued under applicable statutory authority. State regulatory authorities establish similar standards for royalty payments due under state oil and natural 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 natural 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 natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental Regulations

        General.        Our oil and natural 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, also referred to as 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 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 natural gas industry increases the cost of doing business and consequently affects its profitability.

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        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 adversely affect our operations and financial position, as well as those of the oil and natural 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 natural 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 natural 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:

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        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 million while the liability limit for offshore facilities is the payment of all removal costs plus up to $75 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 million ($10 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 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 natural 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.

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        Clean Water Act. The Federal Water Pollution Control Act of 1972, or the Clean Water Act, 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. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water, sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater 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 furtherance of the Clean Water Act, 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, if necessary to ensure compliance, in February 2006 with the implementation of such amended plans in August 2006. 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 natural 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 natural 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, 2004, we had 171 full-time employees, including 12 senior level geoscientists and 17 petroleum engineers. Our employees are not represented by any labor union. 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 with 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.

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Item 2.  Properties

Summary of Oil and Natural Gas Properties and Projects

Rocky Mountain Region

        Our Rocky Mountain operations include assets in the states of North Dakota, Montana, Colorado, Utah, Wyoming and in the Canadian province of Alberta. As of January 1, 2005, our proved reserves in the Rocky Mountain region were 320.4 Bcfe (80.4% oil), which accounted for 37.0% of our total estimated proved reserves. The majority of our reserves in the Rocky Mountain region are in North Dakota and Wyoming. Approximately 52% of the proved reserves of our Rocky Mountain operations are related to assets in North Dakota. Our Canadian assets consist solely of our 50% working interest in the Cessford Field located in southern Alberta, with total proved reserves of 5.8 Bcfe and a pre-tax PV10% value of $13.2 million.

        Big Stick (Madison) Unit. The Big Stick Field, which contains the Big Stick (Madison) Unit, is located in Billings County, North Dakota and produces from a series of stacked, oil saturated, porous dolomites within the Mission Canyon Formation at an average depth of 9,400 feet. We operate this unit and own a 62% working interest. We completed a detailed reservoir model study of the Mission Canyon Formation in 2003. Specifically, this study indicated that production to date accounts for only 18% of the estimated 276 MMbbls of oil originally in place within the Mission Canyon horizon. In 2004, efforts were directed towards improving operating efficiency and increasing lift capacity. This program resulted in 2004 daily equivalent oil production to average 2,100 barrels of oil equivalent per day, an increase of 10% over 2003. Further development plans for the field include shooting a 3-D seismic survey over the field and the drilling of additional vertical and horizontal wells. Additional opportunities exist in the deeper Duperow and the Red River formations. As proven by our fourth quarter 2003 discovery, the Egly #11-20 well, we believe that the Duperow and the Red River Formations can be economically developed with vertical wells and existing infrastructure.

        Nisku A Drilling Program. We made a significant exploration discovery in 2004 in western Billings County, North Dakota in the Nisku A. In the third quarter of 2004, we re-entered the MOI Stillwater 21-23H well bore and drilled a 2,690 foot horizontal lateral in the Nisku A formation. The well had an initial production rate of 397 barrels of oil per day and 256 Mcf of gas per day on a 25/64th-inch choke with 200 pounds per square inch flowing tubing pressure. After this exploration success, we quickly ramped up activity in the area and by the end of 2004, we had drilled a total of ten wells in this play. Of the ten wells, nine were successfully completed. The remaining well, which was drilled on the edge of the expected productive area to help delineate the productive area of the play, was abandoned. Our gross year end 2004 production exit rate from the Nisku A wells totaled 1,630 bopd and 1.0 MMcf/d. During 2004 we participated in (but did not operate) the drilling of several grassroots wells on the western side of the play with encouraging initial results. In 2005, we plan to continue drilling a combination of casing-exit and grass-roots lateral wells on our Nisku A acreage.

        The “A” zone of the Nisku Formation is a thin, two to four foot dolomite bed encased between two impermeable anhydrite beds creating a regional stratigraphic trap that is present over more than 100 square miles. These geologic conditions make the Nisku A an ideal horizontal drilling candidate. We currently hold 33,000 prospective net acres in Billings and Golden Valley Counties, North Dakota.

        Green River Basin—Siberia Ridge. In Southwestern Wyoming in the Green River Basin, we established a position in a multi-well low risk resource play in the Siberia Ridge Field in Sweetwater County through our 2004 acquisition of Equity Oil Company. The primary target in the field is the Cretaceous Almond Formation at a depth of 10,500 feet. We hold over 2,200 gross (1,580 net) undeveloped acres in this play with a working interest ranging between 50 and 100 percent. In 2004, our acreage in the field was down-spaced to allow a second well on each 160 acre spacing unit. In 2005, we plan to drill up to 15 wells in Siberia Ridge.

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Permian Basin Region

        Our Permian Basin operations include assets in Texas and New Mexico. As of January 1, 2005, the Permian Basin region contributed 276.3 Bcfe (80% crude oil) of net proved reserves to our portfolio of operations, which represents 31.9% of our total estimated proved reserves. Approximately 84% of the proved reserves of our Permian Basin operations are related to properties in Texas.

        Parkway (Delaware) Unit. We own a 61.6% non-operated working interest in the Parkway (Delaware) Unit, which is concentrated on 920 gross acres in Eddy County, New Mexico. December 2004 net production averaged 840 bopd and 420 Mcf/d of natural gas. An enhanced oil recovery project currently underway involves drilling eight additional producing wells designed to convert the current waterflood configuration from a five-spot to a nine-spot pattern.

        Would Have Field. We own an approximately 86% operated working interest in the Would Have Field in Howard County, Texas, with net December 2004 production of 1,740 bopd and 1,470 Mcf/d of natural gas from 49 wells. Discovered in 2001, this field produces from two sub-units of the Clearfork Formation, the Would Have and the Dillard Limestones. A waterflood was initiated in the western half of the field in May 2004 and efforts are underway to expand the flood to the eastern portion of the field. Our drilling program in the Would Have field benefits from the use of proprietary 3-D seismic data which has a direct impact on our ability to define areas of reservoir development. The Would Have Field is only partially developed, with both infill and step-out locations remaining to be drilled.

        Signal Peak Field. As of December 31, 2004, our Signal Peak property was contributing 244 bopd and 5.2 MMcf/d net to our interest. We own an average working interest of 75% in the 84 wells we operate, and 25% working interest in 24 wells operated by others. The Signal Peak Field produces from the Wolfcamp Formation, with behind-pipe Clearfork potential identified in several wells. We are currently conducting a selective development drilling program and are evaluating the potential for enhanced gas recovery by increased density well spacing.

        Keystone Field. Our 100% working interest in the Keystone Field provides both substantial production (360 bopd and 1.4 Mcf/d of natural gas, net based on December 2004 production rates) and a large portfolio of additional exploration and development opportunities. The property covers a surface area of 7,260 acres in Winkler County, Texas. Most current production comes from the Clearfork Formation, with additional production from the Wichita-Albany, Wolfcamp, Devonian, Silurian, McKee and Ellenburger. The abundance of producing horizons in the Keystone Field has resulted in several behind-pipe recompletion opportunities. Current drilling at the Keystone Field is targeting the shallow Wichita-Albany Formation. We believe that development of deeper pay horizons will benefit from a 3-D seismic survey which we plan to conduct this year.

        DEB Field. We own a 100% working interest in the DEB Field that covers 740 acres in Gaines County, Texas and produces 880 bopd and 55 Mcf/d net, based on December 2004 production rates from nine wells. The Wolfcamp reservoir is subdivided into two productive intervals, the A and the B, that both produce and are commingled in several wells. Current injection into the Wolfcamp is approximately 19,800 barrels of water per day and oil production in this long-life property has remained relatively flat for many years. Modifications have recently been completed increasing the fluid handling capability of the facilities. This will allow submersible pumps with increased capacity to be installed. We have identified additional drilling opportunities which we plan to pursue in 2005.

Gulf Coast Region

        Our Gulf Coast operations include assets located in Texas, Louisiana and Mississippi. As of January 1, 2005, the Gulf Coast region contributed 131.5 Bcfe (82% natural gas) of net proved reserves to our portfolio of operations, which represented 15.2% of our total net proved reserves. Approximately 78% of the proved reserves of our Gulf Coast operations are related to properties in Texas.

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        Stuart City Reef Trend. In June 2001, we acquired 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 2004, we had an active drilling program in the Edwards Limestone and Wilcox Formation, drilling a total of nine wells. We drilled five horizontal Edwards Limestone wells in the Kawitt and Yoakum Fields located in Dewitt and Karnes, Counties Texas, with varying results. These technically challenging wells are drilled horizontally at 14,000 feet with bottom hole temperatures at or above 350 degrees Fahrenheit. Two of the wells, the Julia Mott #6H (81% working interest) and the Rhodes Trust #3H (100% working interest), had a combined initial production rate over 6.4 MMcfe/d. Two of these wells encountered temperature-related mechanical problems and were temporarily abandoned, and one was a dry hole. We believe that a significant gas resource is present in our Edwards Limestone reservoirs and are working to resolve technical problems encountered in these wells before proceeding in 2005.

        Leveraging our 2003 drilling success in the Rhodes Trust #2H discovery, we began a development drilling program targeting the Wilcox Formation at 10,000 feet in the third quarter 2004. During the remainder of 2004, we drilled four Wilcox wells which were producing at a combined rate of 3.6 MMcfe/d net to our interest at December 31, 2004. We expect to continue an active Wilcox drilling program in 2005 with a combination of up to 18 horizontal and vertical wells.

        Vicksburg Trend. Our holdings in the Vicksburg and Frio Trends are concentrated in the Agua Dulce, Triple A, South Midway, and East White Point fields in Nueces and San Patricio Counties, Texas. We have significant ongoing operations in both Agua Dulce and South Midway fields where we drilled or participated in eight new wells or recompletions. These operations resulted in production increases of 6.1 MMcfe/d and 319 bopd net to our interest.

Michigan Region

        As of January 1, 2005, Michigan accounted for 11.2% of our total estimated proved reserves, or 96.7 Bcfe. In December 2004, the area produced 20.0 MMcfe per day, or 10.6% of our total daily output. Production in Michigan can be divided into two groups. The majority of the reserves are in non-operated Antrim Shale wells. 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 Stoney Point natural gas processing plants. These plants are in excellent 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 57 multi-well Antrim Shale natural gas projects with proved producing reserves and ongoing development drilling. During 2004, we participated in the drilling and completion of 50 Antrim Shale wells. In 2005, we plan to continue to pursue the development drilling opportunities and work with one of the operators who has initiated a successful re-frac program.

        Conventional Production. Our conventional production is primarily from the Prairie du Chien, Glenwood and Trenton Black River Formations located in central Michigan. We own interests in over 20 fields in this area, of which we operate seven.

        The Prairie du Chien fields produce natural gas and retrograde condensate from various intervals within a 500 to 800 foot thick sequence of sandstones and dolomitic sandstones at a depth of 10,500 to 11,200 feet. The low permeability and heterogeneous character of the Prairie du Chien reservoirs has resulted in low recovery of the original natural gas in place from the existing wells, providing us with significant opportunities for increased recovery through infill and horizontal drilling. We plan to drill three wells early in 2005.

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Mid-Continent Region

        Our Mid-Continent operations include assets in Oklahoma, Arkansas and Kansas. As of January 1, 2005, the Mid-Continent region contributed 29.4 Bcfe (57.7% natural gas) of net proved reserves to our portfolio of operations, which represented 3.4% of total net proved reserves. The majority of the proved value within our Mid-Continent operations is related to properties in Oklahoma. The Oklahoma production is scattered throughout the state, with the single largest concentration being in the company-operated Putnam Oswego Unit, located in Dewey and Custer Counties in West-Central Oklahoma.

        Our proved properties located in Arkansas are operated, and are primarily in two fields, the Magnolia Smackover Pool Unit and the Wesson Hogg Sand Unit. Both of these fields are mature pressure maintenance units.

California Region

        As of January 1, 2005, our California operations contributed 11.1 Bcfe (100% natural gas) of net proved reserves to our portfolio of operations, which represented 1.3% of our total net proved reserves. Our assets in this region are located in the State of California, including an operated 100% working interest in 27 producing gas wells and associated leasehold primarily in the Todhunters Lake and Willow Slough Fields of Yolo County, California. We also own non-operated working interests in Colusa and Glenn Counties, California.

Acreage

        The following table summarizes gross and net developed and undeveloped acreage at December 31, 2004 by region (net acreage is our percentage ownership of gross acreage). Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.

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Production History

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

Productive Wells

        The following table presents our ownership at December 31, 2004 in productive oil and natural gas wells by region (a net well is our percentage ownership of a gross well).

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.

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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 2004.

EXECUTIVE OFFICERS OF THE REGISTRANT

        The following table sets forth certain information, as of February 15, 2005, regarding the executive officers of Whiting Petroleum Corporation:

        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 natural 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.

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        D. Sherwin Artus joined us in January 1989 as Vice President of Operations and became Executive Vice President and Chief Operating Officer in July 1999. In January 2000, he was appointed President and Chief Executive Officer and a director. In January 2002, he became Senior Vice President. He has been in the oil and natural gas business for over forty years. Mr. Artus holds a Bachelor’s Degree in geologic engineering and a Master’s Degree in mining engineering from the South Dakota School of Mines and Technology.

        James R. Casperson joined us in February 2000 as Vice President of Finance and Chief Financial Officer. From June 1985 to February 2000, he was founder and president of Casperson, Inc., a private consulting firm. Mr. Casperson has twenty-six years of financial and operational experience in the oil and natural gas industry. Mr. Casperson holds a Bachelor’s Degree from Texas Tech University. Effective March 1, 2005, Mr. Casperson will resign as Vice President of Finance and Chief Financial Officer.

        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 thirty years of oil and natural 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 a MBA from the University of Denver.

        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 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-four 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.

        Mark R. Williams joined us in December 1983 as Exploration Geologist, becoming Vice President of Exploration and Development in December 1999. He has twenty-three years of experience in the oil and natural 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.

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        Michael J. Stevens joined us in May 2001 as Controller, and became Treasurer in January 2002. 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 natural 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. Effective March 1, 2005, Mr. Stevens will be appointed as Vice President and Chief Financial Officer.

        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.

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PART II

        Whiting Petroleum Corporation’s common stock has been traded on the New York Stock Exchange under the symbol “WLL” since our initial public offering on November 20, 2003. The following table shows the high and low sale prices for our common stock for the periods presented.

        On February 15, 2005, there were 956 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.

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Item 6.   Selected Financial Data

        The consolidated income statement information for the years ended December 31, 2004, 2003 and 2002 and the balance sheet information at December 31, 2004 and 2003 are derived from, and are qualified by reference to, our audited financial statements included elsewhere in this report. The consolidated income statement information for the year ended December 31, 2001 and the balance sheet information at December 31, 2002 and 2001 are derived from audited financial statements that are not included in this report. The consolidated income statement information for the year ended December 31, 2000 and the balance sheet information at December 31, 2000 are derived from our unaudited financial statements that are not included in this report. Our historical results include the results from our recent acquisitions beginning on the following dates: Permian Basin, September 23, 2004; Equity Oil Company, July 20, 2004; Colorado and Wyoming, August 13, 2004; Wyoming and Utah, September 30, 2004; Louisiana and Texas, August 16, 2004; Mississippi, November 3, 2004; and additional Permian Basin interest, December 31, 2004.

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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 natural gas prices; our level of success in exploitation, exploration, development and production activities; 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 recently 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 natural gas in commercially viable quantities; uninsured or underinsured losses resulting from our oil and natural gas operations; our inability to access oil and natural gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and natural 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 natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and natural gas industry; and risks arising out of our hedging transactions. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this report.

Overview

        We are engaged in oil and natural gas exploitation, acquisition, exploration and production activities primarily in the Rocky Mountains, Permian Basin, Gulf Coast, Michigan, Mid-Continent and California regions of the United States. Over the last four years, we have emphasized the acquisition of properties that provided current production and significant 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. During periods of radically changing prices, we focus our emphasis on drilling and development of our owned properties. When prices stabilize, we generally direct the majority of our capital to acquisitions.

        We have historically acquired operated as well as 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 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 are of the opinion 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.

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

2004 Acquisitions

        We completed seven separate acquisitions of producing properties during 2004. The combined purchase price for these seven acquisitions was $535.1 million for total estimated proved reserves as of the effective dates of the acquisitions of approximately 436.1 Bcfe. 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: Equity Oil Company, July 20, 2004; Permian Basin, September 23, 2004; Wyoming and Utah, September 30, 2004; Colorado and Wyoming, August 13, 2004; Louisiana and Texas, August 16, 2004; Mississippi, November 3, 2004; and additional Permian Basin interest, December 31, 2004.

Permian Basin Properties

        On September 23, 2004, we acquired interests in seventeen fields in the Permian Basin of West Texas and Southeast New Mexico, including interests in key fields such as Parkway Field in Eddy County, New Mexico; Would Have and Signal Peak Fields in Howard County, Texas; Keystone Field in Winkler County, Texas; and the DEB Field in Gaines County, Texas. The purchase price was $345.0 million in cash and was funded through borrowings under our bank credit agreement. Based on the purchase price and estimated proved reserves of 251.1 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.37 per Mcfe of estimated proved reserves.

Equity Oil Company

        We acquired 100% of the outstanding stock of Equity Oil Company on July 20, 2004. In the merger, we issued approximately 2.2 million shares of our common stock to Equity’s shareholders and repaid all of Equity’s outstanding debt of $29.0 million under its credit facility. Equity’s operations are focused primarily in California, Colorado, North Dakota and Wyoming. Based on the purchase price of $72.6 million and estimated proved reserves of 87.7 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $0.83 per Mcfe of estimated proved reserves.

Other Cash Acquisitions of Properties

        Colorado and Wyoming Properties. On August 13, 2004, we acquired interests in four producing oil and gas fields in Colorado and Wyoming. The purchase price was $44.2 million in cash and was funded under our bank credit agreement. Based on the purchase price of $44.2 million and estimated proved reserves of 39.8 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.11 per Mcfe of estimated proved reserves.

        Louisiana and South Texas Properties. On August 16, 2004, we acquired interests in five fields in Louisiana and South Texas. The purchase price was $19.3 million in cash and was funded under our bank credit agreement. Based on the purchase price of $19.3 million and estimated proved reserves of 12.0 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.61 per Mcfe of estimated proved reserves.

        Wyoming and Utah Properties. On September 30, 2004, we acquired interests in three operated fields in Wyoming and Utah. The purchase price was $35.0 million in cash and was funded under our bank credit agreement. Based on the purchase price of $35.0 million and estimated proved reserves of 30.8 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.14 per Mcfe of estimated proved reserves.

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        Mississippi Properties. On November 3, 2004, we acquired an interest in the Lake Como Field in Mississippi. The purchase price was $12.0 million in cash and was funded under our bank credit agreement. Based on the purchase price of $12.0 million and estimated proved reserves of 10.6 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.43 per Mcfe of estimated proved reserves.

        Additional Permian Basin Interest. On December 31, 2004, we acquired an additional working interest in the Would Have Field in Texas. The purchase price was $7.0 million in cash and was funded under our bank credit agreement. Based on the purchase price and estimated proved reserves of 4.1 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.72 per Mcfe of estimated proved reserves.

Results of Operations

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

        Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

        Oil and Natural Gas Sales. Our oil and natural gas sales revenue increased approximately $105.3 million to $281.1 million in 2004. Sales are a function of sales volumes and average sales prices. Our sales volumes increased 26.6% between periods on a Mcfe basis. The volume increase resulted from successful drilling and acquisition activities over the past year that produced new sales volumes that more than offset natural decline. Our average price for natural gas sales increased 16.3% and our average price for crude oil increased 40.8% between periods.

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        Loss on Oil and Natural Gas Hedging Activities. We hedged 32.3% of our natural gas volumes during 2004 incurring no hedging loss or gain, and 41% of our natural gas volumes during 2003 incurring a hedging loss of $7.7 million. We hedged 50.3% of our oil volumes during 2004 incurring a hedging loss of $4.9 million, and 8.0% of our oil volumes during 2003 incurring a loss of $1.0 million. See Item 7A, “Qualitative and Quantitative Disclosures About Market Risk” for a list of our outstanding oil and natural gas hedges as of February 15, 2005.

        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. At December 31, 2004, we had no investments in marketable securities.

        Gain on Sale of Oil and Gas Properties. During the third quarter of 2004, we sold certain undeveloped acreage held by production 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 is equal to the gross proceeds of $1.0 million.

        Lease Operating Expenses. Our lease operating expenses per Mcfe decreased from $1.16 during 2003 to $1.15 during 2004. The decrease was less than 1%, which represented improved operating efficiency more than offsetting price inflation caused by increased demand for goods and services in the industry. Our fourth quarter 2004 lease operating expense per Mcfe was also $1.15, indicating that the seven acquisitions we completed during the third and fourth quarters of 2004 have not significantly affected this rate.

        Production Taxes. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenue before the effects of hedging. We take full advantage of all credits and exemptions allowed in the various taxing jurisdictions. Due to our broad asset base, we expect our production tax rate to vary between 5.8% to 6.2% of oil and natural gas sales revenue. Our production taxes for 2004 and 2003 were 6.0% and 6.1% of oil and natural gas sales, respectively.

        Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) increased $12.8 million to $54.0 million for 2004. The increase resulted from increased production and an increase in the DD&A rate, as well as the effects of our recent acquisitions. On a Mcfe basis, the rate increased from $1.11 during 2003 to $1.15 in 2004. The increase in rate is primarily due to 2004 property acquisitions, which we purchased at an average cost of $1.23 per Mcfe, which was higher than our historical rate. Changes to the pricing environment can also 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):

        Exploration and Impairment Costs. Our exploration and impairment costs increased $3.1 million to $6.3 million in 2004. The higher exploratory costs were related to our increased purchases of seismic data in 2004 to support our increased drilling budget. The impairment charge represents the write down of cost associated with the High Island Field located off the coast of Texas.

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        General and Administrative Expenses. We report general and administrative expense net of reimbursements. The components of our general and administrative expense were as follows: