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

FORM 10-K

(Mark One)

[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2003

or

[     ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to ___________

Commission file number   001-31899

Whiting Petroleum Corporation
(Exact name of registrant as specified in its charter)

Delaware
(State of other jurisdiction of incorporation or organization)

20-0098515
(I.R.S. Employer Identification No.)

1700 Broadway, Suite 2300
Denver, Colorado

(Address of principal executive offices)

80290-2300
(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
New York Stock Exchange
(Title of Class) (Name of each exchange on which registered)

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    [     ] No    [ X ]

Aggregate market value of the voting stock held by nonaffiliates of the registrant at June 30, 2003:   Not applicable.

Number of shares of the registrant’s common stock outstanding at February 15, 2004:

18,750,000 Shares

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2004 Annual Meeting of Stockholders are incorporated by reference into Part III.



TABLE OF CONTENTS


Forward Looking Statements
Definitions

PART I


Item 1

Business

Item 2 Properties 11 
Item 3 Legal Proceedings 16 
Item 4 Submission of Matters to a Vote of Security Holders 16 
Executive Officers of the Registrant 17 

PART II

19 

Item 5

Market for the Registrant's Common Equity and Related Stockholder Matters

19 
Item 6 Selected Financial Data 20 
Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations 21 
Item 7A Quantitative and Qualitative Disclosure About Market Risk 31 
Item 8 Financial Statements and Supplementary Data 33 
Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 37 
Item 9A Controls and Procedures 37 

PART III

37 

Item 10

Directors and Executive Officers of the Registrant

37 
Item 11 Executive Compensation 37 
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 37 
Item 13 Certain Relationships and Related Transactions 37 
Item 14 Principal Accountant Fees and Services 37 

PART IV

54 

Item 15

Exhibits, Financial Statement Schedules, and Reports on Form 8-K

37 







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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 the pending merger with Equity Oil Company; 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 facility; 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.

DEFINITIONS

        Unless the context otherwise requires, the terms “Whiting,” “we,” “us,” “our” or “ours” when used in this Annual Report on Form 10-K refer to Whiting Petroleum Corporation, together with its only operating subsidiary, Whiting Oil and Gas Corporation. When the context requires, we refer to these entities separately. The term “Alliant Energy,” when used in this report, refers to Alliant Energy Corporation, our former parent company.

        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.

        “Boe” Barrels of oil equivalent, determined using the ratio of six thousand cubic feet of natural gas to one barrel of oil.

        “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.

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        “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.

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

        “MMboe” One million barrels of oil equivalent.

         “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.

        “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

        We are engaged in oil and natural gas exploitation, acquisition, exploration and production activities primarily in the Gulf Coast/Permian Basin, Rocky Mountains, Michigan and Mid-Continent regions of the United States. Our focus is on pursuing growth projects that we believe will generate attractive rates of return and maintain 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, 2004, our estimated proved reserves had a pre-tax PV10% value of approximately $784.6 million, approximately 85% of which came from properties located in three states: Texas, North Dakota and Michigan. We spent approximately $52.0 million on capital projects during 2003, including $38.8 million for the drilling of 72 gross (24.8 net) wells (64 successful completions and eight uneconomic wells). We have budgeted approximately $68.0 million for capital expenditures in 2004, including $33.0 million for the development of proved reserves and $35.0 million for the development of currently unproved reserves. Although we have no specific budget for acquisitions, we will also continue to seek property acquisition opportunities that complement our existing core properties. We believe that our exploitation and acquisition expertise and our exploration inventory, together with our operating experience and efficient cost structure, provide us with the potential to continue our growth.

        We have a balanced portfolio of oil and natural gas reserves, with approximately 53% of our proved reserves consisting of natural gas and approximately 47% 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 trailing 12 month production ending December 31, 2003 of approximately 11.8 years. Approximately 75% of our proved reserves are classified as proved developed and approximately 25% are classified as proved undeveloped.

        The following table summarizes our total net proved reserves and pre-tax PV10% value within our four core areas as of January 1, 2004, as well as our December 2003 average daily production.

Proved Reserves
December 2003
Average Daily
Production

Core Area
Oil
(MMbbl)

Natural
Gas
(Bcf)

Total
(Bcfe)

Pre-Tax PV
10% Value
(In thousands)

MMcfe
% Natural
Gas

Gulf Coast/Permian Basin      5.5    89.4    122.5   $ 266,745    40.0    76 %
Rocky Mountains    26.5    17.6    176.5    261,071    32.3    11 %
Michigan    1.1    107.2    114.1    214,407    21.3    92 %
Mid-Continent    1.5    16.8    25.7    42,400    8.2    73 %






     Total    34.6    231.0    438.8   $ 784,623    101.8    59 %







        Prior to our initial public offering in November 2003, we were a wholly-owned subsidiary of Alliant Energy Corporation, an energy services provider engaged primarily in regulated utility operations in the Midwest, with other non-regulated domestic and international operations.

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:

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        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. We own interests in a total of 517,000 gross (206,000 net) developed acres. In addition, as of December 31, 2003, we owned interests in approximately 386,000 gross (188,000 net) undeveloped acres that contain many exploitation opportunities. Over the three years ended December 31, 2003, we have invested $94 million to participate in the drilling of 169 gross (60.6 net) wells. The majority of these wells have been developmental wells, and 85.2% were successful completions. As of January 1, 2004, we had identified a total of 171 proved undeveloped drilling locations on our properties. We drilled or participated in the drilling of 72 gross (24.8 net) wells during the year ended December 31, 2003. We plan to invest $68 million on the further development of our properties in 2004.

        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 and engineering and geoscience professionals who identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties.

        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.

        Controlling Costs through Efficient Operation of Existing Properties. We operate approximately 60% of the pre-tax PV10% value of our total proved reserves and approximately 82% of the pre-tax PV10% value of our proved undeveloped reserves, which we believe enables us to better manage expenses, capital allocation and the decision-making processes related to our exploitation and exploration activities. For the year ended December 31, 2003, our lease operating expense per Mcfe averaged $1.16 and general and administrative costs averaged $0.34 per Mcfe produced, net of reimbursements.

Competitive Strengths

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

        Diversified Asset Base. We have interests in 5,006 wells in 16 states across our four core geographical areas of the United States. 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 26 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 653 square miles of 3-D seismic data, which we have assembled primarily over the past five years. A team with access to state-of-the-art geophysical/geological computer applications and hardware analyzes this information. 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 technology and expertise has greatly aided our pursuit of attractive development projects.

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Proved Reserves

        Our proved reserves as of January 1, 2004 are summarized in the table below.

Oil
(MBbl)

Natural Gas
(MMcf)

Total
(Bcfe)

% of Total
Proved

Pre-tax
PV10%
(In
thousands)

Future Capital
Expenditures
(In thousands)

Gulf Coast/Permian Basin:                            
     PDP    4,300    52,322    78.1    17.8 % $ 172,347   $ 2,784  
     PDNP    287    6,232    8.0    1.8 %  20,465    1,141  
     PUD    939    30,856    36.4    8.3 %  73,933    25,794  






         Total Proved:     5,526     89,410     122.5     27.9 % $ 266,745   $ 29,719  






Rocky Mountains:   
     PDP    18,898    13,183    126.6    28.8 % $ 169,051   $ 743  
     PDNP    571    205    3.6    0.8 %  4,340    393  
     PUD    7,008    4,257    46.3    10.6 %  87,680    18,774  






         Total Proved:       26,477     17,645     176.5     40.2 % $ 261,071   $ 19,910  






Michigan:   
     PDP    469    76,263    79.1    18.0 % $ 133,618   $ 0  
     PDNP    140    6,914    7.8    1.8 %  23,854    1,713  
     PUD    536    24,017    27.2    6.2 %  56,935    14,755  






         Total Proved:       1,145     107,194     114.1     26.0 % $ 214,407   $ 16,468  






Mid-Continent:   
     PDP    1,438    15,900    24.5    5.6 % $ 41,271   $ 0  
     PDNP    53    863    1.2    0.3 %  1,129    229  






         Total Proved:       1,491     16,763     25.7     5.9 % $ 42,400   $ 229  






Total Corporate:   
     PDP    25,105    157,668    308.3    70.2 % $ 516,287   $ 3,527  
     PDNP    1,051    14,214    20.6    4.7 %  49,788    3,476  
     PUD    8,483    59,130    109.9    25.1 %  218,548    59,323  






         Total Proved:       34,639     231,012     438.8     100 % $ 784,623   $ 66,326  







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 2003, 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. Our 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.

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        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.

        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.

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        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.

        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.

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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 commences, restrict the types, quantities and concentrations of various substances 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 waste 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 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 waste 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 wastes 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 wastes 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 wastes 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 wastes were not under our control. Similarly, the waste disposal facilities where wastes 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. Our properties, adjacent affected properties, the disposal sites, and the waste itself may be subject to CERCLA and analogous state laws. Under these laws, we could be required:

  to remove or remediate previously disposed wastes, including wastes 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.

        At this time, we do not believe that we are associated with 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 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. Liability under OPA is strict, and under certain circumstances joint and several, and potentially unlimited. 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 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 required financial responsibility may be increased above the minimum amounts to an amount not exceeding $150 million, depending on the risk represented by the quantity or quality of oil that is handled by the facility. We believe we are in compliance with all applicable OPA financial responsibility obligations. Any failure to comply with OPA's requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions. 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.

9


        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 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 applicable 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, imposes restrictions and controls on the discharge of produced waters and other wastes 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 for 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 updated SPCC plans beginning in early 2004. 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 updating of our SPCC plans will not have a significant impact on our operations.

10


        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, 2003, we had 110 full-time employees, including five senior level geoscientists and fourteen 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.

Item 2.       Properties

Summary of Oil and Natural Gas Properties and Projects

Gulf Coast/Permian Basin Region

        Our Gulf Coast/Permian Basin operations include assets in Texas, Louisiana, Alabama and New Mexico. The Gulf Coast/Permian Basin region contributes 122.5 Bcfe (73% natural gas) of net proved reserves to our portfolio of operations, which represents 27.9% of our total net proved reserves. Approximately 90.9% of the proved reserves of our Gulf Coast/Permian Basin operations are related to properties in Texas.

        Stuart City Reef Trend. We have leasehold interests in five fields located along a regional geologic structure known as the Stuart City Reef Trend in south-central Texas, where we are employing horizontal drilling technologies to develop gas reserves in the Edwards Limestone at 14,000 feet. Our Stuart City properties contain 35.5 Bcfe of net proved reserves primarily within the Word North field, the Yoakum field and the Kawitt field. During 2003, we drilled three successful Edwards wells in these fields. We plan to continue development of our Edwards gas reserves by drilling a combination of new horizontal wells and casing-exit horizontal wells. We have also begun an active drilling program targeting the Wilcox Formation at 10,000 feet. During 2003, we drilled one Wilcox well and plan additional drilling in the Kawitt and Word North fields.

        Vicksburg Trend. We own interests in several fields within the Vicksburg Trend located in the vicinity of Nueces Bay in San Patricio and Nueces Counties, Texas. These fields include the Agua Dulce, Triple A, South Midway, and East White Point fields. Natural gas and oil production in this area is from multiple, low permeability sandstone reservoirs within the Vicksburg and Frio Formations at depths ranging between 4,000 and 15,000 feet.

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        In the Agua Dulce field, we operate 13 wells with a 99.0% average working interest. Our properties in this field contain 17.7 Bcfe of net proved reserves. We have begun an active development program at Agua Dulce where we are employing 3-D seismic to exploit multiple, low permeability gas sands within a highly faulted anticline. During 2003 we drilled one successful gas well, but had mechanical difficulties in completing a second well and are currently sidetracking the wellbore. We plan to continue the development of our gas reserves through the acquisition of additional seismic data and new drilling.

        Gulf of Mexico. In South Timbalier Block 185, we have an 18% working interest in a successful, non-operated drilling and recompletion project in of the Gulf of Mexico shelf area, offshore Louisiana. We also have interests in ongoing drilling activity in South Timbalier, Blocks 185, 200 and 203, which we expect to continue during 2004.

        Cotton Valley Reef Trend. We are involved in an exploration play along the Cotton Valley Reef trend primarily in Leon and Robertson counties, Texas. Fields along this trend produce gas from pinnacle reefs within the Cotton Valley formation at 14,000 feet. We are employing modern seismic processing techniques to accurately delineate these reservoirs. We are currently drilling one of these wells and plan one additional well in 2004.

Rocky Mountain Region

        Our Rocky Mountain operations include assets in North Dakota, Montana, Colorado and Wyoming. As of January 1, 2004, our proved reserves in the Rocky Mountain region were 29.4 MMboe (90% oil), which accounted for 40.2% of our total proved reserves. The majority of our interests in the Rocky Mountain region are within North Dakota and Montana, where we have interests in 97 fields, 45 of which we operate. Approximately 87% of the proved reserves of our Rocky Mountain operations are related to assets in North Dakota.

        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. Our net recoverable reserves at Big Stick at year end were 12.6 MMboe. Since acquiring this property, we have increased unit oil production by 14% through a combination of workovers and sidetracks of existing wells as well as new drilling. During the past year, we have been engaged in a detailed reservoir modeling study to determine the benefits and feasibility of implementing a waterflood within the unit. We are also developing our deeper, non-unitized interests at Big Stick, and recently drilled a new well which identified gas pay in the Red River Formation at 12,700 feet and oil pay in the Duperow Formation at 11,000 feet.

        North Elkhorn Ranch Unit. The North Elkhorn Ranch Unit is located eight miles north of the Big Stick field in Billings County, North Dakota and also produces from reservoirs within the Mission Canyon Formation. We hold a 60% working interest and operate this unit. Our net recoverable reserves are 4.5 MMboe. Since assuming unit operations in May of 2002, we have reversed the decline in unit production, primarily through workovers of existing wells and reduction in downtime. We drilled one unit well late in 2003 and plan additional development drilling during 2004.

        Red Water Field. We have a 40% non-operated working interest in an active exploration and development play which targets the middle member of the Mississippian Bakken Formation in Richland County, Montana. During 2003 we drilled four new horizontal wells which have estimated ultimate recoveries of 500 to 800 Mboe per well. At year end, our net recoverable reserves from the Red Water Field were 1.2 MMboe.

        Sioux Field. We have a 65% working interest and operate this field which is located in McKenzie County, North Dakota. This field produces oil and gas from multiple zones at depths up to 13,700 feet. Since acquiring this property in 2002, we have increased production by 130% primarily through new drilling and recompletions. In 2003, we drilled a successful well with up to eight producing zones. Initially, production will be from the Interlake Formation which has tested oil at approximately 250 barrels of oil per day.

12


Michigan Region

        Our Michigan operations include assets in Michigan and Ohio. Virtually all of the proved reserves and pre-tax PV10% value associated with our Michigan operations are from properties located in the State of Michigan. The Michigan region contributes 114.1 Bcfe (94% natural gas) of net proved reserves to our portfolio of operations, which represents 26% of our total net proved reserves.

        The majority of our Michigan production is from a non-conventional natural gas reservoir in the northern Michigan basin known as the Antrim Shale. The remainder of our production is from a variety of conventional oil and natural gas reservoirs in the eastern and southern portions of the basin. We operate the majority of our non-Antrim production as well as the West Branch and Stoney Point natural gas plants, while the majority of our Antrim production is operated by local companies in close cooperation with our technical staff.

        Antrim Production. Natural gas is produced from fractures within the Antrim Shale at depths from 1,200 to 2,200 feet. The productive fairway of the Antrim is widespread across northern Michigan, covering a 3,400 square mile region. We own interests in 57 multi-well Antrim Shale natural gas projects within this area. As of January 1, 2004, our net proved reserves from these projects were 79.6 Bcfe (100% natural gas).

        Approximately 10 of our Antrim Shale projects have significant remaining development potential. These projects are concentrated in three areas. In Briley Township, we have proved undeveloped reserves of 5.9 Bcf. The Old Vandy Projects in Charlevoix and Otsego Counties have proved undeveloped reserves of 2.0 Bcf. An additional 4.9 Bcf of proved undeveloped reserves are present within eight additional townships which are less geographically concentrated. During 2003, we drilled 15 wells, and we expect to drill 20 wells during 2004.

        Conventional (non-Antrim) Production. Our non-Antrim Shale production is from conventional reservoirs (primarily the Prairie du Chien, Trenton and Black River Formations) located in Central Michigan. Estimated net proved reserves from these properties total 34.5 Bcfe (80% natural gas). We have interests in 20 oil and natural gas fields in this region and operate 7 of them.

        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.

        Our undeveloped potential resides in three fields, West Branch, Clayton and South Buckeye. All are structurally trapped hydrocarbon accumulations and to date recoveries range from 4% to 37% of the in place hydrocarbons. Our undeveloped proved reserve potential in these three fields is estimated at 14.4 Bcfe versus 60 Bcfe produced to date. Two locations have been identified for drilling in 2004. We believe that significant additional potential exists for horizontal re-entry wells and conventional vertical and horizontal wells.

Mid-Continent Region

        Our Mid-Continent operations include assets in Oklahoma, Arkansas and Kansas. The Mid-Continent region contributes 25.7 Bcfe (65% natural gas) of net proved reserves to our portfolio of operations, which represents 5.9% 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.

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        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.

        Cherokee Basin Coalbed Methane Project. In 2002 and 2003, we acquired a 91,284 acre lease position in the Cherokee Basin, which is prospective for natural gas from coal seams (coalbed methane). Approximately 70,000 acres are concentrated in our Center prospect, which is located south of Emporia, Kansas and in which we have a 100% working interest. Eight stratigraphic test wells were drilled during 2003 and evaluation efforts are ongoing.






14


Acreage

        The following table summarizes gross and net developed and undeveloped acreage at December 31, 2003 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.

Developed Acreage   
Undeveloped Acreage   
Total Acreage   
Gross   
Net   
Gross   
Net   
Gross   
Net   
Gulf Coast/Permian Basin      159,603    58,813    8,514    7,518    168,117    66,331  
Rocky Mountains    137,038    66,507    286,000    90,400    423,038    156,907  
Michigan    179,141    59,000    --    --    179,141    59,000  
Mid-Continent    40,740    21,438    91,284    90,395    132,024    111,833  






         Total    516,522    205,758    385,798    188,313    902,320    394,071  







Production History

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

Year Ended December 31,
2003
2002
2001
Oil production (MMbbls)      2.6    2.3    2.1  
Natural gas production (Bcf)    21.6    21.4    19.8  
Total production (Bcfe)    37.2    35.2    32.4  
Daily production (MMcfe/d)    101.8    96.4    88.8  
Average sales prices:  
     Natural gas (per Mcf)(1)   $ 4.78   $ 3.21   $ 3.82  
     Oil (per Bbl)(1)    27.50    23.35    23.85  
         Total (per Mcfe)(1)    4.73    3.48    3.88  
Costs and expenses (per Mcfe):  
   Lease operating expenses   $ 1.16   $ 0.93   $ 0.92  
   Production taxes    0.29    0.21    0.20  
   Depreciation, depletion and amortization expense    1.11    1.24    1.11  
   General and administrative expenses, net of reimbursements    0.34    0.34    0.34  


(1)     Before consideration of hedging transactions.

15


Productive Wells

        The following table presents our ownership at December 31, 2003 in productive oil and natural gas wells by region (a net well is our percentage ownership of a gross well).

Oil Wells
Natural Gas Wells
Total Wells
Gross
Net
Gross
Net
Gross
Net
Gulf Coast/Permian Basin      1,571    139.7    852    282.0    2,423    421.7  
Rocky Mountains    863    254.7    115    17.9    978    272.6  
Michigan    78    57.0    968    368.3    1,046    425.3  
Mid-Continent    372    151.2    187    78.8    559    230.0  






         Total    2,884    602.6    2,122    747.0    5,006    1,349.6  







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.

Gulf Coast/Permian Basin
Mid-Continent
2003
2002
2001
2003
2002
2001
Gross:                            
   Productive    22    10    22    2    3    3  
   Dry    3    6    6    --    --    --  






       Total    25    16    28    2    3    3  






Net:  
   Productive    10.6    4.2    10.5    0.1    0.2    1.0  
   Dry    .9    2.2    1.9    --    --    --  






       Total    11.5    6.4    12.4    0.1    0.2    1.0  







Rocky Mountains
Michigan
Total
(continued)
2003
2002
2001
2003
2002
2003
2002
2001
Gross:                                    
   Productive    25    7    31    15    4    64    24    56  
   Dry    5    3    2    --    --    8    9    8  








       Total    30    10    33    15    4    72    33    64  








Net:  
   Productive    7.4    2.7    8.1    2.8    1.0    20.9    8.1    19.6  
   Dry    3.0    2.1    1.9    --    --    3.9    4.3    3.8  








       Total    10.4    4.8    10.0    2.8    1.0    24.8    12.4    23.4  









        Our drilling activity from exploratory wells, which are included in the above table, include one productive gross well (0.2 net) in 2001 in the Gulf Coast/Permian Basin region, one dry gross well (0.15 net) in 2002 in the Gulf Coast/ Permian Basin region, three dry gross wells (1.55 net) in 2003, two of which were located in the Rocky Mountain region and one in the Gulf Coast/Permian Basin region.

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

    (a)        A special meeting of the sole stockholder of Whiting Petroleum Corporation was held on November 25, 2003, immediately prior to the initial public offering of Whiting Petroleum Corporation’s common stock. At the time of the special meeting, Alliant Energy Resources, Inc. (“Resources”) was the sole stockholder of Whiting Petroleum Corporation.

16


    (b)        Not Applicable.

    (c)        The following matters brought for vote at the Special Meeting passed by the vote indicated:

Shares Voted
For
Against
Withheld
Broker
Non-Vote

1.


Approval of the Whiting
Petroleum Corporation 2003
Equity Incentive Plan
18,330,000 0 0 0

2.



Approval of the Whiting Oil
and Gas Corporation Phantom
Equity Plan

18,330,000

0

0

0



EXECUTIVE OFFICERS OF THE REGISTRANT

        The following table sets forth certain information, as of February 15, 2004, regarding the executive officers of Whiting Petroleum Corporation:

Name          
Age
Position     
James J. Volker 57  Chairman, President and Chief Executive Officer
D. Sherwin Artus 66  Senior Vice President
James R. Casperson 56  Chief Financial Officer
James T. Brown 51  Vice President, Operations
John R. Hazlett 64  Vice President, Acquisitions and Land
Mark R. Williams 47  Vice President, Exploration and Development
Patricia J. Miller 66  Vice President of Human Resources and Corporate Secretary
Michael J. Stevens 38  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 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.

        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 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.

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        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-five years of financial and operational experience in the oil and natural gas industry. Mr. Casperson holds a Bachelor’s Degree from Texas Tech University.

        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 twenty-nine 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.

        John R. Hazlett joined us in January 1994 as Vice President of Land and Acquisitions. He has forty years of experience in the oil and natural gas industry as a land man and acquisitions team leader. Mr. Hazlett is a graduate of Ft. Hays State College in Hays, Kansas. Mr. Hazlett is a Certified Professional Landman.

        Mark R. Williams joined us in December 1983 as Exploration Geologist, becoming Vice President of Exploration and Development in December 1999. He has twenty-two 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.

        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. Mrs. Miller attended business school at Otero Junior College in LaJunta, Colorado and at Texas A & I in Kingsville, Texas.

        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.

        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

Item 5.    Market for the Registrant’s Common Equity and Related Stockholder Matters

        Whiting Petroleum Corporation’s common stock is traded on the New York Stock Exchange under the symbol “WLL.” The following table sets forth the range of high and low closing sales prices for our common stock for the period from November 20, 2003 (the first day of trading of the common stock on the New York Stock Exchange) through December 31, 2003. Prior to November 20, 2003, no public market existed for our common stock.

High         
Low   
Fourth quarter (November 20, 2003 through
   December 31, 2003)
    $ 18.54   $ 16.15  

        On February 15, 2004, there were nine stockholders of record and approximately 6,500 beneficial owners of our common stock.

        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, our credit facility prohibits us from paying dividends.











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Item 6. Selected Financial Data

        The consolidated income statement information for the years ended December 31, 2003, 2002 and 2001 and the balance sheet information at December 31, 2003 and 2002 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 years ended December 31, 2000 and 1999 and the balance sheet information at December 31, 2000 and 1999 are derived from our unaudited financial statements, which are not included in this report. The balance sheet information at December 31, 2001 is derived from audited financial statements that are not included in this report.

Year Ended December 31,    
2003    
2002    
2001    
2000    
1999   
(dollars in millions except per share data)
Consolidated Income Statement Information:
Revenues:                        
   Oil and gas sales   $ 175.7   $ 122.7   $ 125.2   $ 107.0   $ 60.9  
   Gain (loss) on oil and gas hedging activities .    (8.7 )  (3.2 )  2.3    (3.8 )  --  
   Gain on sale of oil and gas properties    --    1.0    11.7    7.7    10.1  
   Interest income and other    0.3    --    0.2    0.1    0.1  





      Total revenues   $ 167.3   $ 120.5   $ 139.4   $ 111.0   $ 71.1  





Costs and expenses:  
   Lease operating   $ 43.2   $ 32.9   $ 29.8   $ 23.8   $ 20.7  
   Production taxes    10.7    7.4    6.5    5.4    3.0  
   Depreciation, depletion and amortization    41.2    43.6    26.9    21.5    19.8  
   Impairment of proven oil and gas properties    --    --    --    --    3.3  
   Exploration    3.2    1.8    0.8    1.1    1.9  
   Phantom equity plan    10.9    --    --    --    --  
   General and administrative    12.8    12.0    10.9    6.3    4.3  
   Interest expense    9.2    10.9    10.2    7.5    5.4  





      Total costs and expenses   $ 131.2   $ 108.6   $ 85.1   $ 65.0   $ 58.4  





Income before income taxes and cumulative change   $ 36.1   $ 11.9   $ 54.3   $ 45.4   $ 12.7  
Income tax expense    13.9    4.2    13.1    11.7    1.8  





Income from continuing operations    22.2    7.7    41.2    33.7    10.9  
Cumulative change in accounting principle    3.9    --    --    --    --  





Net income   $ 18.3   $ 7.7   $ 41.2   $ 33.7   $ 10.9  





Basic and diluted net income per common share from continuing operations   $ 1.18   $ 0.41   $ 2.20   $ 1.80   $ 0.58  





Basic and diluted net income per common share   $ 0.98   $ 0.41   $ 2.20   $ 1.80   $ 0.58  





Other Financial Information:   
Net cash provided by operating activities   $ 96.4   $ 62.6   $ 62.3   $ 42.3   $ 38.7  
Capital expenditures   $52.0   $165.4   $99.6   $139.1   $34.9  

As of December 31,    
2003    
2002    
2001    
2000    
1999   
(dollars in millions except per share data)
Balance Sheet Information:                        
 Total assets   $ 536.3   $ 448.5   $ 319.8   $ 256.4   $ 148.5  
 Long-term debt   $188.0   $265.5   $163.6   $139.7   $72.5  
 Stockholder's equity   $ 259.6   $ 122.8   $ 111.5   $ 70.0   $ 36.2  

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

Overview

        We are engaged in oil and natural gas exploitation, acquisition, exploration and production activities primarily in the Gulf Coast/Permian Basin, Rocky Mountains, Michigan and Mid-Continent 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 management is 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.

        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.

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Results of Operations

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

Years Ended December 31,   
2003   
2002   
2001   
Net production:                
     Natural gas (Bcf)    21.6    21.4    19.8  
     Oil (MMbbls)    2.6    2.3    2.1  
Net sales (in millions):  
     Natural gas(1)    $ 104.4   $ 68.6   $ 75.4  
     Oil(1)    $ 71.3   $ 54.1   $ 49.8  
Average sales price:  
     Natural gas (per Mcf)(1)    $ 4.78   $ 3.21   $ 3.82  
     Oil (per Bbl)(1)    $ 27.50   $ 23.35   $ 23.85  
Costs and expenses (per Mcfe):  
     Lease operating expenses   $ 1.16   $ 0.93   $ 0.92  
     Production taxes   $ 0.29   $ 0.21   $ 0.20  
     Depreciation, depletion and amortization expense   $ 1.11   $ 1.24   $ 1.11  
     General and administrative expenses, net of reimbursements   $ 0.34   $ 0.34   $ 0.34  


(1)     Before consideration of hedging transactions.

        Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

        Oil and Natural Gas Sales. Oil and natural gas sales revenue increased approximately $53.0 million to $175.7 million in 2003. Natural gas sales increased $35.8 million and oil sales increased $17.2 million. The natural gas sales increase was caused by a 49% increase in the average realized natural gas price from $3.21 per Mcf in 2002 to $4.78 per Mcf in 2003 combined with a 230,000 Mcf volume increase in natural gas sales between years. The oil sales increase was caused by a sales volume increase of 275,000 Bbls in 2003 and an 18% increase in the average realized oil price from $23.35 in 2002 to $27.50 in 2003. The volume increase for oil and natural gas primarily resulted from the $217 million of capital expenditures during 2002 and 2003.

        Loss on Oil and Natural Gas Hedging Activities. We hedged 41% of our natural gas volumes during 2003, incurring a hedging loss of $7.7 million, and 8% of our natural gas volumes during 2002, incurring a loss of $0.2 million. We hedged 8% of our oil volumes during 2003, incurring a hedging loss of $1.0 million, and 35% of our oil volumes during 2002, incurring a loss of $3.0 million.

        Gain on Sale of Oil and Natural Gas Properties. In 2002, we divested one property, realizing a gain of $1.0 million. No significant properties were sold in 2003.

        Lease Operating Expenses. Our lease operating expenses per Mcfe increased from $0.93 in 2002 to $1.16 in 2003. The increase resulted from acquisitions during 2002 that caused a larger portion of our operations to be located in Michigan and North Dakota, where weather conditions, sulfur content and remote locations create higher operating costs in comparison to other areas of operation.

        Production Taxes. Production taxes as a percentage of oil and natural gas sales were 6.1% in 2003 and 6.0% in 2002. The small increase in the effective rate resulted from additional property purchases in the states of North Dakota and Montana, where effective production tax rates are higher on average than other areas where we own significant producing properties.

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        Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased by $2.3 million in 2003. The decrease was a result of a decrease in the average rate from $1.24 per Mcfe in 2002 to $1.11 per Mcfe in 2003, partially offset by increased sales volumes in 2003. The lower rate was a result of higher prices between periods, which allowed for a longer economic production life and corresponding increased reserve volumes and, as a result, a lower depreciation, depletion and amortization rate.

        Exploration Costs. Exploration costs increased $1.4 million to $3.2 million for 2003. The increase was the result of recording three exploratory dry holes during 2003 compared to one exploratory dry hole in 2002.

        General and Administrative Expenses. General and administrative expenses increased 6.9%, or $0.8 million, to $12.8 million in 2003. This increase was related to increases in compensation expense associated with increased personnel required to administer our growth and to general cost inflation.

        Phantom Equity Plan Compensation. The completion of our initial public offering in November 2003 constituted a "triggering event" under our phantom equity plan. Under this plan, our employees received compensation of $10.9 million in the form of 420,000 shares of our common stock after withholding of shares by us for estimated payroll and income taxes. The phantom equity plan is now terminated.

        Interest Expense. Interest expense decreased $1.8 million to $9.2 million in 2003 compared to $10.9 million in 2002. The decrease was due lower average debt levels in 2003 and lower effective interest rates in 2003. The lower debt levels were primarily related to a March 2003 decision by Alliant Energy to convert its remaining $80.9 million of intercompany debt into our equity thereby lowering our future interest expense.

        Income Tax Expense. Our effective tax rate was 38.6% in 2003 and 35.3% during 2002. The increased effective tax rate was in part due to our 2002 acquisitions in the state of North Dakota where the effective state income tax rate is higher on average than other areas where we own significant producing properties. In addition, during 2002 we generated $5.4 million of Section 29 credits that we were not able to offset against tax expense. Under our tax separation and indemnification agreement with Alliant Energy, we expect to be compensated for these credits in the future when they are utilized by Alliant Energy. Under generally accepted accounting principles, the recording of the tax credits in 2002 were required to be charged as additional paid-in capital rather than as a decrease to our 2002 income tax expense. Section 29 tax credit provisions of the Internal Revenue Code expired December 31, 2002. Therefore, unless additional legislation is passed, Section 29 credits will not be available in periods subsequent to 2002.

        Cumulative Change in Accounting Principle. Effective January 1, 2003, we adopted the provisions of SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement generally applies to legal obligations associated with the retirement of long-lived assets and requires us to recognize the fair value of asset retirement obligations in our financial statements by capitalizing that cost as a part of the cost of the related asset. This statement applies directly to plug and abandonment liabilities associated with our net working interest in well bores. The additional carrying amount is depleted over the estimated useful lives of the properties. The discounted liability is based on historical abandonment costs in specific areas and is accreted at the end of each accounting period through charges to accretion expense. The liability is discounted using a credit-adjusted risk-free rate of approximately 7%. If the obligation is settled for other than the carrying amount, a gain or loss is recognized on settlement. Upon adoption of AFAS No. 143, we recorded an increase to our discounted abandonment liability of $16.4 million, increased proved property cost by $10.1 million and recognized a one-time cumulative effect charge of $3.9 million (net of a deferred tax benefit of $2.4 million).

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        Net Income. Net income increased from $7.7 million in 2002 to $18.3 million in 2003. The primary reasons for this increase included higher crude oil and natural gas prices between periods and higher volumes sold, offset by higher lease operating, tax and general and administrative costs due to our growth.

        Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

        Oil and Natural Gas Sales. Oil and natural gas sales revenue decreased approximately $2.6 million to $122.7 million in 2002. Natural gas sales decreased $6.8 million, while oil sales increased $4.2 million. The natural gas sales decrease was caused by a 16% decline in the average realized natural gas price from $3.82 Mcf in 2001 to $3.21 Mcf in 2002, partially offset by an increase in natural gas production of 1.6 Bcf in 2002. The oil sales increase was caused by a sales volume increase of 200,000 Bbls in 2002, partially offset by a 2% decline in the average realized oil price from $23.85 in 2001 to $23.35 in 2002. The volume increase for oil and natural gas was due to $265 million of capital expenditures during 2001 and 2002.

        Loss on Oil and Natural Gas Hedging Activities. We hedged 8% of our natural gas volumes during 2002, incurring a hedging loss of $0.2 million, and 11% of our natural gas volumes during 2001, incurring a gain of $1.6 million. We hedged 35% of our oil volumes during 2002, incurring a hedging loss of $3.0 million, and 17% of our oil volumes during 2001, incurring a gain of $0.7 million.

        Gain on Sale of Oil and Natural Gas Properties. In 2002, we divested only one property, realizing a gain of $1.0 million, while in 2001, we divested several properties, realizing total sales gains of $11.7 million.

        Lease Operating Expenses. Our lease operating expenses per Mcfe increased from $0.92 in 2001 to $0.93 in 2002. The increase resulted from acquisitions during 2002 that caused a larger portion of our operations to be located in Michigan and North Dakota, where weather conditions, sulfur content and remote locations create higher operating costs.

        Production Taxes. Production taxes as a percentage of oil and natural gas sales were 6.0% in 2002 and 5.2% in 2001. The increase in the effective rate resulted from additional property purchases in the states of North Dakota and Montana, where effective production tax rates are higher on average than other areas where we own significant producing properties.

        Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense in 2001 included a $9.0 million reduction related to the abandonment liability for the Point Arguello platform located offshore from California. During 2001, we received a revised and more detailed dismantlement plan from the operator. The $9.0 million reduction of liability was credited against depreciation, depletion and amortization expense since the liability was initially created by charges to depreciation, depletion and amortization expense. Without this credit, our depreciation, depletion and amortization expense charge for 2001 would have been $35.9 million. The increase to $43.6 million of depreciation, depletion and amortization expense in 2002 was a result of increasing sales volumes and an increased rate from $1.11 per Mcfe in 2001 to $1.24 per Mcfe in 2002.

        Exploration Costs. Exploration costs increased $1.0 million to $1.8 million for 2002 compared with $0.8 million for 2001. The increase was partially the result of a $420,000 charge for an exploratory dry hole in 2002. The remaining increase in 2002 is related to the further development and processing of our geophysical library.

        General and Administrative Expenses. General and administrative expenses increased 9.5% or $1.1 million from $10.9 million in 2001 to $12.0 million in 2002. This increase was related to increases in compensation expense associated with increased personnel required to administer our growth and to general cost inflation.

        Interest Expense. Interest expense increased $0.7 million to $10.9 million in 2002 compared to $10.2 million in 2001. The increase was due to higher average debt levels in 2002 to fund our growth, partially offset by a lower effective interest rate.

24


        Income Tax Expense. Our effective tax rate before tax credits was 36.8% in 2002 and 36.2% in 2001. In 2001, we were able to reduce our tax expense by $6.6 million due to the recording of Section 29 tax credits. In 2002, we generated $5.4 million of Section 29 credits that we were not able to offset against tax expense. Under our tax separation and indemnification agreement with Alliant Energy, we expect to be compensated for these credits in the future when they are utilized by Alliant Energy. Under generally accepted accounting principles, the recording of the tax credits in 2002 were required to be charged as additional paid-in capital rather than as a decrease to our 2002 income tax expense. Section 29 tax credit provisions of the Internal Revenue Code expired December 31, 2002. Therefore, unless additional legislation is passed, Section 29 credits will not be available in periods subsequent to 2002.

        Net Income. Net income decreased from $41.2 million in 2001 to $7.7 million in 2002. The primary reasons were a $19.0 million decline in revenues, a $23.5 million increase in expenses and the inability to recognize $5.4 million of tax credits as a reduction of tax expense. The revenue decrease was caused by a decline in oil and natural gas prices between years and $10.7 million less gains from the sales of properties in 2002. The expense increase was caused by the $9.0 million reduction to 2001 depreciation, depletion and amortization related to the adjustment of the Point Arguello abandonment liability and cost increases in all other categories to operate and administer the property acquisitions during 2001 and 2002.

Liquidity and Capital Resources

        Cash Flows. During the year ended December 31, 2003, we generated $96.4 million from operating activities and received $4.6 million in contributions from Alliant Energy. We used a portion of these cash proceeds to fund $52.0 million of capital expenditures. At December 31, 2003, we had $53.6 million of cash on hand and $51.3 million of working capital compared to December 31, 2002 when our cash position was $4.8 million and working capital was $19.4 million.

        We continually evaluate our capital needs and compare them to our capital resources. Our budgeted capital expenditures for the further development of our property base is $68.0 million during 2004. Although we have no specific budget for property acquisitions, we will continue to seek property acquisition opportunities that complement our existing core property base. We expect to fund our development expenditures from internally generated cash flow during 2004. We believe that should attractive acquisition opportunities arise or development expenditures exceed $68.0 million, we could finance the additional capital expenditures with cash on hand, operating cash flow, additional borrowings under our credit facility, issuances of additional equity or development with industry partners. The level of capital expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among other factors.

        Credit Facility. Whiting Oil and Gas Corporation has a $350.0 million credit agreement with a syndicate of banks. At December 31, 2003, the credit agreement provided a borrowing base of $210.0 million with an outstanding principal balance of $185.0 million. On February 17, 2004, we repaid $40.0 million of the outstanding principal balance from cash on hand in excess of projected drilling and production needs. The borrowing base under the credit agreement is based on the collateral value of our proved reserves and is subject to redetermination on May 1 and November 1 of each year. If the borrowing base is determined to be lower than the outstanding principal balance then drawn, we must immediately pay the difference. The credit agreement provides for interest only payments until December 20, 2005, when the entire amount borrowed is due. Interest accrues, at our option, at either (1) the base rate plus a margin where the base rate is defined as the higher of the federal funds rate plus 0.5% or the prime rate and the margin varies from 0.25% to 1.0% depending on the ratio of the amounts borrowed to the borrowing base, or (2) at the LIBOR rate plus a margin where the margin varies from 1.5% to 2.25% depending on the ratio of the amounts borrowed to the borrowing base. At December 31, 2003, all amounts outstanding under the credit agreement bore interest at an annual rate of 3.21% through February 6, 2004. On February 6, 2004, we fixed the rate on the outstanding principal balance at an annual rate of 3.2% through August 6, 2004. The credit agreement has covenants that restrict the payment of cash dividends, borrowings, sale of assets, loans to others, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders and requires us to maintain certain debt to EBITDAX (as defined in our credit agreement) ratios and a working capital ratio. The credit agreement also precludes us from providing any cash to Alliant Energy except for services rendered on an arm's-length basis or for income taxes. We were in compliance with our covenants under the credit agreement as of December 31, 2003. The credit agreement is secured by a first lien on substantially all of Whiting Oil and Gas Corporation's assets. Whiting Petroleum Corporation has agreed to guarantee the obligations of Whiting Oil and Gas Corporation under the credit agreement.

        As part of an overall review of our liquidity and financial condition, we are currently considering refinancing all or a portion of the outstanding debt under our credit agreement through the issuance of senior subordinated debt securities with long term maturities. In addition, if our acquisition of Equity Oil Company closes, then we intend to assume Equity Oil's outstanding debt under its credit facility, which was $29.0 million as of December 31, 2003. See "- Subsequent Event." We will be required to amend our credit agreement to permit this assumption of debt.



25


        Historical Financing. Prior to our initial public offering in November 2003, we functioned as an indirect wholly-owned subsidiary of Alliant Energy. As a result, our liquidity was directly related to the financial resources and capital expenditure allocations of Alliant Energy. In the past, Alliant Energy provided a capital expenditure budget and funded net cash requirements beyond cash generated from operations. Until our $185.0 million bank borrowing in December 2002 as described above, we did not rely on outside sources of borrowing or capital. Instead, we received advances on Alliant Energy's intercompany credit facility, which primarily covered the shortfall between our capital expenditures (including acquisitions) and cash generated from operations and property sales. The table below describes net borrowings and payments on Alliant Energy's intercompany credit facility.

Year Ended December 31,
2003
2002
2001
Total
Alliant Energy(1)     $ (80.9 ) $ (83.1 ) $ 23.9   $ (140.1 )
Whiting credit facility    --    185.0    --    185.0  




Total   $ (80.9 ) $ 101.9   $ 23.9   $ 44.9  





(1)  In March 2003, Alliant Energy converted its remaining loan plus accrued interest of $80.9 million to "paid in capital" of Whiting.

        Tax Separation and Indemnification Agreement with Alliant Energy. In connection with our initial public offering in November 2003, we entered into a tax separation and indemnification agreement with Alliant Energy. Pursuant to this agreement, we and Alliant Energy made a tax election with the effect that the tax basis of the assets of Whiting Oil and Gas Corporation and its subsidiaries were increased to the deemed purchase price of their assets immediately prior to such initial public offering. We have adjusted deferred taxes on our balance sheet to reflect the new tax basis of our assets. This additional basis is expected to result in increased future income tax deductions and, accordingly, may reduce income taxes otherwise payable by us. Under this agreement, we have agreed to pay to Alliant Energy 90% of the future tax benefits we realize annually as a result of this step-up in tax basis for the years ending on or prior to December 31, 2013. Such tax benefits will generally be calculated by comparing our actual taxes to the taxes that would have been owed by us had the increase in basis not occurred. In 2014, we will be obligated to pay Alliant Energy the present value of the remaining tax benefits assuming all such tax benefits will be realized in future years. The initial recording of this transaction in November 2003 resulted in a $57.2 million increase in deferred tax assets, a $28.6 million discounted payable to Alliant Energy and a $28.6 million increase to stockholders’ equity.

        Alliant Energy Promissory Note. In conjunction with our initial public offering in November 2003, we issued a promissory note payable to Alliant Energy in the aggregate principal amount of $3.0 million. The note bears interest at an annual rate of 5%. All principal and interest on the promissory note are due on November 25, 2005.


26


        Schedule of Contractual Obligations. The following table summarizes our obligations and commitments as of December 31, 2003 to make future payments under certain contracts, aggregated by category of contractual obligation, for specified time periods.

Payments due by period
Contractual Obligations
Total
Less than
1 year

1-3 years
3-5 years
More than
5 years

Long-Term Debt     $ 188.0    --   $ 188.0    --    --  
Operating Leases    2.0   $ 1.1    0.9    --    --  
Tax Separation and Indemnification Agreement  
     with Alliant Energy(1)     28.8    --    4.2   $ 3.1   $ 21.5  





Total   $ 218.8   $ 1.1   $ 193.1   $ 3.1   $ 21.5  






(1)  Amounts shown are estimates based on estimated future income tax benefits from the increase in tax basis described under "Tax Separation and Indemnification Agreement with Alliant Energy" above.

        Off-Balance Sheet Arrangements. As part of a 2002 purchase transaction, we agreed to share with the seller 50% of the actual price received for certain crude oil production in excess of $19.00 per barrel. The agreement runs through December 31, 2009 and contains a 2% price escalation per year. As a result, the sharing amount at January 1, 2004 increased to 50% of the actual price received in excess of $19.77 per barrel. Currently, approximately 46,000 net barrels of crude oil per month (21% of December 2003 net crude oil production) are subject to this sharing agreement. The terms of the agreement do not provide for a maximum amount to be paid. As of December 31, 2003, we have paid $3.1 million under this agreement and we have accrued an additional $215,000 as currently payable.

New Accounting Policies

        In June 2001, the Financial Accounting Standards Board, or the FASB, issued Statement of Financial Accounting Standards, or SFAS, No. 141, “Business Combinations,” which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB issued SFAS No. 142, “Goodwill and Other Intangible Assets,” which discontinues the practice of amortizing goodwill and indefinite-lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. We did not change or reclassify the contractual mineral rights included in our oil and natural gas properties on the balance sheet upon adoption of SFAS No. 142. We believe that the current accounting of such mineral rights as part of crude oil and natural gas properties is appropriate under the successful efforts method of accounting. However, there is an alternative view that reclassification of mineral rights to an intangible asset may be necessary. If a reclassification of contractual mineral rights acquired subsequent to July 1, 2001 from oil and gas properties to long term intangible assets is required, then the reclassified amounts would be approximately $48.7 million as of December 31, 2001, $161.2 million as of December 31, 2002 and $160.1 million as of December 31, 2003. We do not believe that the ultimate outcome of this issue will have a significant impact on our cash flows, results of operations or financial condition.

        Effective January 1, 2003, we adopted the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations.” This statement generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 requires us to recognize the fair value of asset retirement obligations in our financial statements by capitalizing that cost as a part of the cost of the related asset. In regards to us, this statement applies directly to the plug and abandonment liabilities associated with our net working interest in well bores. The additional carrying amount is depleted over the estimated lives of the properties. The discounted liability is based on historical abandonment costs in specific areas and is accreted at the end of each accounting period through charges to accretion expense. The liability is discounted using a credit-adjusted risk-free rate of approximately 7%. If the obligation is settled for other than the carrying amount, a gain or loss is recognized on settlement. Upon adoption of SFAS No. 143, we recorded an increase to our discounted abandonment liability of $16.4 million, increased proved property cost by $10.1 million and recognized a one-time cumulative effect charge of $3.9 million (net of a deferred tax benefit of $2.4 million). We have an additional $4.3 million abandonment liability relating to our retained obligation with respect to the Point Arguello facility located offshore from California.

27


        In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associates with Exit or Disposal Activities.” This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (“EITF”) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. The adoption of this Statement had no impact on our financial statements.

        FASB Interpretation No. 45, or FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” was issued in November 2002 by the FASB. FIN 45 requires a guarantor to recognize a liability for the fair value of the obligation it assumes under certain guarantees. Additionally, FIN 45 requires a guarantor to disclose certain aspects of each guarantee, or each group of similar guarantees, including the nature of the guarantee, the maximum exposure under the guarantee, the current carrying amount of any liability for the guarantee, and any recourse provisions allowing the guarantor to recover from third parties any amounts paid under the guarantee. The disclosure provisions of FIN 45 are effective for financial statements for both interim and annual periods ending after December 15, 2002. The fair value measurement provisions of FIN 45 are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The adoption of this statement did not have a material impact on our financial statements.

        In January 2003, the FASB issued FASB Interpretation No. 46, or FIN 46 (as revised in December 2003), “Consolidation of Variable Interest Entities.” FIN 46 clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated support from other parties. FIN 46 requires existing unconsolidated variable interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. All companies with interests in variable interest entities created after January 31, 2003, shall apply the provisions of FIN 46 to those entities immediately. The adoption of this Statement had no impact on our financial statements.

        In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” to amend and clarify financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. The changes in this statement require that contracts with comparable characteristics be accounted for similarly to achieve more consistent reporting of contracts as either derivative or hybrid instruments. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003 and will be applied prospectively. The adoption of this Statement had no impact on our financial statements.

        In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” to classify certain financial instruments as liabilities in statements of financial position. The financial instruments are mandatorily redeemable shares, which the issuing company is obligated to buy back in exchange for cash or other assets, put options and forward purchase contracts, instruments that do or may require the issuer to buy back some of its shares in exchange for cash or other assets, and obligations that can be settled with shares, the monetary value of which is fixed, tied solely or predominantly to a variable such as a market index, or varies inversely with the value of the issuers’ shares. Most of the guidance in SFAS No. 150 is effective for all financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this Statement had no impact on our financial statements.


28


Critical Accounting Policies and Estimates

        Our discussion of financial condition and results of operation is based upon the information reported in our consolidated financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. Our significant accounting policies are detailed in Note 1 to our consolidated financial statements. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.

        Revenue Recognition. We predominantly derive our revenue from the sale of produced crude oil and natural gas. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received; however, differences have been insignificant.

        Hedging.        Our crude oil and natural gas hedges are designed to be treated as cash flow hedges under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activity.” This policy is significant since it impacts the timing of revenue recognition. Under this pronouncement, the majority of our hedging gains or losses are recorded in the month the contracts settle. We reflect this as an adjustment to revenue through the “Gain (loss) on oil and gas hedging activities” line item in our consolidated income statements. If our hedges did not qualify for cash flow hedge treatment, then our consolidated income statements could include large non-cash fluctuations in this line item, particularly in volatile pricing environments, as our contracts are marked to their period end market values.

        Successful Efforts Accounting. We account for our oil and natural gas operations using the successful efforts method of accounting. Under this method, all costs associated with property acquisition, successful exploratory wells and all development wells are capitalized. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells and oil and natural gas production costs. All of our properties are located within the continental United States and the Gulf of Mexico.

        Oil and Natural Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Reserve quantities and future cash flows included in this report are prepared in accordance with guidelines established by the SEC and FASB. The accuracy of our reserve estimates is a function of:

  the quality and quantity of available data;

  the interpretation of that data;

  the accuracy of various mandated economic assumptions; and

  the judgments of the persons preparing the estimates.



29


        Our proved reserve information included in this report is based on estimates prepared by Ryder Scott Company, Cawley, Gillespie & Associates, Inc. and R.A. Lenser & Associates, Inc., each independent petroleum engineers, and Whiting Oil and Gas Corporation’s engineering staff. The independent petroleum engineers evaluated approximately 83% of the pre-tax PV10% value of our proved reserves and Whiting Oil and Gas Corporation’s engineering staff evaluated the remainder. Estimates prepared by others may be higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. We continually make revisions to reserve estimates throughout the year as additional information becomes available. We make changes to depletion rates and impairment calculations in the same period that changes to the reserve estimates are made.

        Impairment of Oil and Natural Gas Properties. We review the value of our oil and natural gas properties whenever management judges that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. We provide for impairments on undeveloped property when we determine that the property will not be developed or a permanent impairment in value has occurred. Impairments of proved producing properties are calculated by comparing future net undiscounted cash flows on a field-by-field basis using escalated prices to the net recorded book cost at the end of each period. If the net capitalized cost exceeds net future cash flows, the cost of the property is written down to “fair value,” which is determined using net discounted future cash flows from the producing property. Different pricing assumptions or discount rates could result in a different calculated impairment. We have not recorded any property impairments since 1999.

        Income Taxes. We provide for income taxes in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes.” Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to actual in the period we file our tax returns.

Effects of Inflation and Pricing

        We experienced increased costs during 2001, 2002 and 2003 due to increased demand for oil field products and services. The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Material changes in prices impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, continued high prices for oil and natural gas could result in increases in the cost of material, services and personnel.

Subsequent Event

        On February 2, 2004, we announced that we entered into a definitive merger agreement to acquire Equity Oil Company. The merger agreement provides for a stock-for-stock merger under which Equity shareholders will receive a fixed exchange ratio of 0.185 shares of our common stock for each share of Equity common stock that they own. In addition, we will assume approximately $29 million of Equity debt. The merger is subject to the approval of shareholders owning two-thirds of the outstanding Equity shares and other customary closing conditions. Equity intends to call a special meeting of its shareholders during the second quarter of 2004 to consider and vote on the merger. We expect to complete the merger as soon as practicable following approval by Equity’s shareholders..


30



Item 7A. Quantitative and Qualitative Disclosure About Market Risk

Commodity Price Risk

        The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. 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 natural gas have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Based on December 2003 production, our income before income taxes moves approximately $2.1 million for every $0.10 change in natural gas prices and approximately $2.4 million for each $1.00 change in crude oil prices.

        We periodically enter into derivative contracts to manage our exposure to oil and natural gas price volatility. Our derivative contracts have traditionally been with no-cost collars, although we evaluate other forms of derivative instruments as well. Our derivative contracts have historically qualified for cash flow hedge accounting under SFAS No. 133. This accounting treatment allows the aggregate change in fair market value to be recorded as other comprehensive income on the consolidated balance sheet. Recognition in the consolidated income statement occurs in the period of contract settlement. We generally limit our aggregate hedge position to less than 50% of expected production, but may hedge larger percentages of total expected production in certain circumstances. We do not intend to hedge in excess of 60% of our expected production. We also seek to diversify our hedge position with various counterparties where we have clear indications of their current financial strength.

        Our hedging arrangements have the effect of locking in for specified periods the prices we will receive for the volumes and commodity to which the hedge relates. Consequently, while these hedges are designed to decrease our exposure to price decreases, they also have the effect of limiting the benefit of price increases. For the natural gas contracts listed below, a hypothetical $0.10 change in the NYMEX price above the ceiling price or below the floor price applied to the notional amounts would cause a change in the gain (loss) on hedging activities of $255,000 in 2004. For the crude oil contracts listed below, a hypothetical $1.00 change in the NYMEX price would cause a change in the gain (loss) on hedging activities of $450,000 in 2004.

        Our outstanding hedges at February 1, 2004 are summarized below:

Commodity
Period
Monthly Volume
(Mmbtu)/(Bbl)  

NYMEX         
Floor/Ceiling    

Natural Gas 01/2004 to 03/2004 300,000    $4.50/7.00 
Natural Gas 01/2004 to 03/2004 250,000    4.50/8.45 
Natural Gas 01/2004 to 03/2004 300,000    4.50/8.05 
Crude Oil 01/2004 to 03/2004 50,000    28.00/31.43 
Crude Oil 01/2004 to 03/2004 50,000    28.00/32.10 
Crude Oil 04/2004 to 06/2004 50,000    28.00/35.40 

        We have also entered into fixed price marketing contracts directly with end users for a portion of the natural gas we produce in Michigan. All of those contracts have built-in pricing escalators of 4% per year. Our outstanding fixed price marketing contracts at December 31, 2003 are summarized below:

Commodity
Period
Monthly Volume (Mmbtu)  
2004 Price per Mmbtu 
Natural Gas 01/2002 to 12/2011    51,000 $4.22       
Natural Gas 01/2002 to 12/2012    60,000 3.74       



31


Interest Rate Risk

        Market risk is estimated as the change in fair value resulting from a hypothetical 100 basis point change in the interest rate on the outstanding under our credit facility. The credit facility allows us to fix the interest rate for all or a portion of the principal balance for a period up to six months. To the extent the interest rate is fixed, interest rate changes affect the instrument’s fair market value but do not impact results of operations or cash flows. Conversely, for the portion of the credit facility that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows. At December 31, 2003, the interest rate on the entire outstanding principal balance under our credit facility was fixed at 3.21% through February 6, 2004. On February 6, 2004, the interest rate on the entire outstanding principal balance was fixed at 3.2% through August 6, 2004. At December 31, 2003, the carrying amount approximated fair market value. Assuming a constant debt level of $185.0 million, the cash flow impact for 2004 resulting from a 100 basis point change in interest rates during periods when the interest rate is not fixed would be $745,000.

















32


Item 8. Financial Statements and Supplementary Data

WHITING PETROLEUM CORPORATION
INDEX TO FINANCIAL STATEMENTS


Independent Auditor's Report
34 

Consolidated Balance Sheets as of December 31, 2003 and 2002
35 

Consolidated Statements of Income for the Years ended December 31, 2003, 2002 and 2001
37 

Consolidated Statements of Stockholders' Equity and Comprehensive Income for the Years ended
   December 31, 2003, 2002 and 2001
38 

Consolidated Statements of Cash Flows for the Years ended December 31, 2003, 2002 and 2001
39 

Notes to Consolidated Financial Statements
40 










33


INDEPENDENT AUDITORS’ REPORT

To the Board of Directors ofWhiting
Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Whiting Petroleum Corporation and Subsidiaries (the “Company”) as of December 31, 2003 and 2002, and the related consolidated statements of income, stockholder’s equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the financial statements, in 2003 the Company changed its method of accounting for asset retirement obligations to conform to Statement of Financial Accounting Standards No. 143.

/s/ DELOITTE & TOUCHE LLP

February 25, 2004
Denver, Colorado








34


WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2003 AND 2002
(In thousands, except per share data)


2003
2002

ASSETS
           

CURRENT ASSETS:
  
     Cash and cash equivalents   $ 53,585   $ 4,833  
     Accounts receivable trade    24,020    22,509  
     Income taxes and other receivables    --    8,162  
     Prepaid expenses and other    2,666    3,542  


         Total current assets    80,271    39,046  

PROPERTY AND EQUIPMENT:
  
     Oil and gas properties, successful efforts method:  
       Proved properties    615,764    553,902  
       Unproved properties    1,637    1,593  
     Other property and equipment    2,684    3,454  


         Total property and equipment    620,085    558,949  

     Less accumulated depreciation, depletion and amortization
    (192,794 )  (154,352 )



Property and equipment--net
    427,291    404,597  



OTHER LONG-TERM ASSETS
    9,988    4,825  

DEFERRED INCOME TAX ASSET
    18,735  



TOTAL
   $ 536,285   $ 448,468  


(Continued)  


35


WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2003 AND 2002
(In thousands, except per share data)


2003
2002

LIABILITIES AND STOCKHOLDERS' EQUITY
           

CURRENT LIABILITIES:
  
     Accounts payable   $ 15,918   $ 8,474  
     Oil and gas sales payable    2,406    903  
     Accrued employee benefits    5,275    4,259  
     Production taxes payable    2,574    2,137  
     Derivative liability    2,145    3,300  
     Income taxes and other liabilities    693    585  


         Total current liabilities    29,011    19,658  

DEFERRED INCOME TAX LIABILITY
    --    28,235  

ABANDONMENT LIABILITY
    23,021    4,232  

PRODUCTION PARTICIPATION PLAN LIABILITY
    7,868    8,053  

TAX SHARING LIABILITY
    28,790    --  

LONG-TERM DEBT
    188,017    265,472  

COMMITMENTS AND CONTINGENCIES
  
(Note 7)  

STOCKHOLDERS' EQUITY:
  
     Common stock, $.001 par value; 18,750,000
        authorized, issued and outstanding
    19    19  
     Additional paid-in capital    170,367    53,219  
     Accumulated other comprehensive loss    (223 )  (1,550 )
     Retained earnings    89,415    71,130  


         Total stockholders' equity    259,578    122,818  



TOTAL
   $ 536,285   $ 448,468  


(Concluded)     


See notes to consolidated financial statements.

36


WHITING PETROLEUM CORPORATION AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001
(In thousands, except per share data)


2003
2002
2001
REVENUES:                
     Oil and gas sales   $ 175,731   $ 122,709   $ 125,286  
     Gain (loss) on oil and gas hedging activities    (8,680 )  (3,184 )  2,266  
     Gain on sale of oil and gas properties    --    978    11,698  
     Interest income and other    330    9    205  



         Total    167,381    120,512    139,455  



COSTS AND EXPENSES:  
     Lease operating    43,213    32,867    29,767  
     Production taxes    10,691    7,363    6,482  
     Depreciation, depletion and amortization    41,256    43,601    26,904  
     Exploration    3,186    1,811    793  
     General and administrative    12,805    11,980    10,939  
     Phantom equity plan    10,914    --    --  
     Interest expense    9,177    10,938    10,233  



         Total costs and expenses    131,242    108,560    85,118  




INCOME BEFORE INCOME TAXES
    36,139    11,952    54,337  

INCOME TAX EXPENSE (BENEFIT):
  
     Current    2,389    (6,408 )  1,815  
     Deferred    11,560    10,631    11,279  



         Total income tax expense    13,949    4,223    13,094  




INCOME FROM CONTINUING OPERATIONS
    22,190    7,729    41,243  

CUMULATIVE CHANGE IN ACCOUNTING PRINCIPLE
    (3,905 )  --    --  




NET INCOME
   $ 18,285   $ 7,729   $ 41,243  



     Basic and diluted earnings per share from continuing operations   $ 1.18   $ 0.41   $ 2.20  
     Cumulative change in accounting principle    (0.20 )  --    --  




BASIC AND DILUTED NET INCOME PER COMMON SHARE
   $ 0.98   $ 0.41   $ 2.20  




WEIGHTED AVERAGE SHARES OUTSTANDING
    18,750    18,750    18,750  




See notes to consolidated financial statements.

37


WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001
(In thousands, except per share data)


Common Stock
Additional
Paid-in
Retained Accumulated
Other
Comprehensive
Total
Stockholders'
Comprehensive
Shares
Amount
Capital
Earnings
Income (Loss)
Equity
Income

BALANCES—January 1, 2001
     18,750   $ 19   $ 47,856   $ 22,158   $ 15   $ 70,048     --  
    Net income    --    --    --    41,243    --    41,243    41,243  
    Unrealized net gain on  
      marketable equity  
      securities for sale    --    --    --    --    88    88    88  
    Reclass to earnings    --    --    --    --    87    87    87  








BALANCES—December 31, 2001
    18,750    19    47,856    63,401    190    111,466    41,418  

    Net income    --    --    --    7,729    --    7,729    7,729  
    Unrealized net gain on  
      marketable equity  
      securities for sale    --    --    --    --    240    240    240  
    Tax contribution from Alliant    --    --    5,363    --    --    5,363    --  
    Change in derivative  
      instrument fair value    --    --    --    --    (1,980 )  (1,980 )  (1,980 )








BALANCES—December 31, 2002
    18,750    19    53,219    71,130    (1,550 )  122,818    5,989  

    Net income    --    --    --    18,285    --    18,285    18,285  
    Unrealized net gain on  
      marketable equity  
      securities for sale    --    --    --    --    664    664    664  
    Change in derivative  
      instrument fair value    --    --    --    --    663    663    663  
    Conversion of Alliant note  
      payable to equity    --    --    80,931    --    --    80,931    --  
    Issuance of note payable    --    --    (3,000 )  --    --    (3,000 )  --  
    Phantom equity plan  
      contribution    --    --    10,666    --    --    10,666    --  
    Tax basis step-up    --    --    28,551    --    --    28,551    --  








BALANCES—December 31, 2003
    18,750   $ 19   $ 170,367   $ 89,415   $ (223 ) $ 259,578   $ 19,612  










See notes to consolidated financial statements.

38


WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
(In thousands, except per share data)


2003
2002
2001
CASH FLOWS FROM OPERATING ACTIVITIES:                
     Net income   $ 18,285   $ 7,729   $ 41,243  
     Adjustments to reconcile net income to net  
      cash provided by operating activities:  
        Gain on sale of oil and gas properties    --    (978 )  (11,700 )
        Depreciation, depletion and amortization    41,256    43,601    35,902  
        Deferred income taxes    11,560    10,631    11,288  
        Amortization of bank fees    1,091    71    --  
        Accretion of tax sharing agreement    220    --    --  
        Phantom equity plan    6,510    --    --  
        Cumulative change in accounting principle    3,905    --    --  
     Changes in assets and liabilities:  
        Accounts receivable    (307 )  (1,129 )  2,165  
        Income taxes and other receivable    3,814    1,538    (5,670 )
        Other assets    295    (1,229 )  315  
        Abandonment liability    (147 )  (48 )  (8,997 )
        Production participation plan    651    1,685    1,473  
        Current liabilities    9,229    710    (3,672 )



           Net cash provided by operating activities    96,362    62,581    62,347  




CASH FLOWS FROM INVESTING ACTIVITIES:
  
     Capital expenditures    (47,555 )  (165,443 )  (99,621 )
     Acquisition of partnership interests, net of cash received    (4,453 )  --    --  
     Proceeds from sale of properties    --    1,534    19,570  
     Restricted cash    --    6,434    (6,434 )



           Net cash used in investing activities    (52,008 )  (157,475 )  (86,485 )




CASH FLOWS FROM FINANCING ACTIVITIES:
  
     Other advances (repayments) from Alliant, net    4,616    (83,119 )  23,869  
     Proceeds from bank loan    --    185,000    --  
     Debt issuance costs    (218 )  (3,171 )  --  



           Net cash provided by financing activities    4,398    98,710    23,869  




NET CHANGE IN CASH AND CASH EQUIVALENTS
    48,752    3,816    (269 )

CASH AND CASH EQUIVALENTS:
  
     Beginning of period    4,833    1,017    1,286  



     End of period   $ 53,585   $ 4,833   $ 1,017  




SUPPLEMENTAL CASH FLOW DISCLOSURES:
  
     Cash paid (refunded) for income taxes--Alliant   $ (1,425 ) $ (7,946 ) $ 8,586  



     Cash paid for interest   $ 6,464   $ 10,866   $ 10,233  




NONCASH FINANCING ACTIVITIES:
  
     Alliant debt converted to equity    80,931    --    --  




See notes to consolidated financial statements.

39


WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001
(In thousands, except per share data)


1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  Description of Operations—Whiting Petroleum Corporation (“Whiting” or the “Company”) is a Delaware corporation that prior to its initial public offering in November 2003 was a wholly owned indirect subsidiary of Alliant Energy Corporation (“Alliant Energy” or “Alliant”), a holding company whose primary businesses are utility companies. Just prior to the public offering of our common stock by Alliant Energy, the Company in effect split its common stock, issuing 18,330 shares for the 1 previously held by Alliant Energy. All periods presented have been adjusted to reflect the current capital structure. Alliant Energy historically provided the Company with cash management and other services. Whiting acquires, develops and explores for producing oil and gas properties primarily in the Gulf Coast/Permian Basin, Rocky Mountains, Michigan, and Mid-Continent regions of the United States.

  Basis of Presentation of Consolidated Financial Statements—The consolidated financial statements include the accounts of Whiting and its subsidiaries, all of which are wholly owned, together with its pro rata share of the assets, liabilities, revenue and expenses of limited partnerships in which Whiting is the sole general partner. All significant intercompany balances and transactions have been eliminated in consolidation.

  Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make significant estimates. These estimates are an integral part of the financial statements and actual results could differ from those estimates. Certain estimates associated with the carrying amount of oil and gas properties are particularly sensitive to changes in pricing, production rates and cost. A decline in the price of oil or gas or rate of production or increase in costs associated with the operations of oil and gas properties could adversely impact the economic value of the oil and gas properties.

  Cash and Cash Equivalents—Cash equivalents consist of money market accounts and investments which have an original maturity of three months or less.

  Fair Value of Financial Instruments—The Company’s financial instruments, including cash and cash equivalents, restricted cash, accounts receivable and payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments. The related party debt and bank loan have a recorded value that approximates its fair value as both instruments have variable interest rates tied to current market rates. The Company’s derivative instruments and investment in available for sale securities are marked-to-market with changes in value being recorded in accumulated other comprehensive income.

  Concentration of Credit Risk—Substantially all of the Company’s receivables are within the oil and gas industry, primarily from the sale of oil and gas products and billings to working interest owners. Although diversified within many companies, collectibility is dependent upon the general economic conditions of the industry. Most of the receivables are not collateralized and to date, the Company has had minimal bad debts.

  Further, our natural gas futures and swap contracts also expose us to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and historically the Company have not experienced material credit losses. The Company believes that our credit risk related to the natural gas futures and swap contracts is no greater than the risk associated with primary contracts and that the elimination of price risk reduces volatility in our reported results of operations, financial position and cash flows from period to period and lowers our overall business risk; but, as a result of Whiting’s hedging activities the Company may be exposed to greater credit risk in the future. No single purchaser of oil and gas accounted for 10% or more of total sales for the years ended December 31, 2003, 2002 or 2001.

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  At December 31, 2003 and 2002, the Company had recorded an allowance for doubtful accounts of $300 and $250 and, respectively.

  Oil and Gas Producing Activities—The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense. The costs of development wells are capitalized whether productive or nonproductive.

  Interest cost is capitalized as a component of property cost for exploration and development projects that require a period of time to be readied for their intended use. During 2003, 2002 and 2001, capitalized interest was insignificant.

  Geological and geophysical costs of exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment is recorded for unproved properties if the capitalized costs are not considered to be realizable. Depletion, depreciation and amortization (“DD&A”) of capitalized costs of proved oil and gas properties is provided on a field-by-field basis using the units of production method based upon proved reserves. The computation of DD&A takes into consideration the anticipated proceeds from equipment salvage and the Company’s expected cost to abandon its well interests.

  The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares future net undiscounted cash flows on a field-by-field basis using escalated prices to the net recorded book cost at the end of each period. If the net capitalized cost exceeds net future cash flows, then the cost of the property is written down to “fair value,” which is determined using net discounted future cash flows from the producing property. Different pricing assumptions or discount rates could result in a different calculated impairment. During 2003, 2002 and 2001, the Company did not record any impairment charges for proved properties.

  Gains and losses are recognized on sales of entire interests in proved and unproved properties. Sales of partial interests are generally treated as recoveries of costs.

  Other Property and Equipment—Other property and equipment are stated at cost and depreciated using the straight-line method over a period of four years. Maintenance and repair costs which do not extend the useful lives of the property and equipment are charged to expense as incurred. When other property and equipment is sold or retired, the related costs and accumulated depreciation are removed from the accounts.

  As of December 31, 2003 and 2002, the balance of other property and equipment was $2,684 and $3,454, respectively. Depreciation expense was approximately $836, $770, and $710 for the years ended December 31, 2003, 2002 and 2001, respectively.

  Bank Fees—Bank fees are being amortized to interest expense using the interest method over the life of the loan.

  Reimbursed Overhead—The Company provides various administrative services to its partnerships and owners of certain oil and gas properties for which the Company receives overhead reimbursements. Amounts earned are included as a reduction to general and administrative expense and totaled $5,631, $5,505 and $5,276, for the years ended December 31, 2003, 2002 and 2001, respectively.

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  Abandonment Liability—Effective January 1, 2003, the Company adopted the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 requires the Company to recognize the fair value of asset retirement obligations in the financial statements by capitalizing that cost as a part of the cost of the related asset. In regards to the Company, this Statement applies directly to the plug and abandonment liabilities associated with the Company’s net working interest in well bores. The additional carrying amount is depleted over the estimated lives of the properties. The discounted liability is based on historical abandonment costs in specific areas and is accreted at the end of each accounting period through charges to depreciation, depletion and amortization expense. If the obligation is settled for other than the carrying amount, then a gain or loss is recognized on settlement.

  Revenue Recognition—The Company uses the sales method to record oil revenues whereby revenue is recognized based on the amount of oil sold to purchasers. The Company uses the entitlements method to record natural gas revenues whereby revenue is recognized for the Company’s share of natural gas produced, regardless of whether the Company has taken its share of the related revenue. In situations where gas imbalances occur, receivables are valued at current market value each reporting period, while liabilities are generally presented based on the price in effect when the imbalance occurred. As of December 31, 2003 and 2002, the Company was in an under produced imbalance position of approximately 206,000 Mcf and 411,000 Mcf.

  Derivative Instruments—Whiting is exposed to market risk in the pricing of its oil and gas production. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, supply and demand factors, transportation availability and price, and general economic conditions. Worldwide political developments have historically also had an impact on oil and gas prices. Periodically, Whiting utilizes oil and gas swaps and forward contracts to mitigate the impact of oil and gas price fluctuations related to its sales of oil and gas. During the years 2003, 2002 and 2001, Whiting entered into a number of oil and gas swaps and forward contracts.

  At December 31, 2003, the Company had five commodity swaps or forward contracts outstanding with a fair market value unrealized loss of $2,145 of which $1,317 was recorded as a component of accumulated other comprehensive loss and $828 was recorded as an increase to the deferred tax asset.

  At December 31, 2002, the Company had four commodity swaps or forward contracts outstanding with a fair market value unrealized loss of $3,300 of which $1,980 was recorded as a component of accumulated other comprehensive loss and $1,320 was recorded as a reduction to the deferred tax liability.

  For the years ended December 31, 2003, 2002, and 2001, Whiting recognized a loss of approximately $8.7 million, a loss of approximately $3.2 million, and a gain of $2.3 million from the settlement of derivative instruments, respectively.

  Marketable Securities—Investments in marketable securities are classified as held-to-maturity, trading securities or available-for-sale. Trading and available-for-sale securities are recorded at estimated market value. Realized gains or losses for both classes of equity investments are determined on a specific identification basis and are included in income. Unrealized gains or losses of available-for-sale securities are excluded from earnings and reported in other comprehensive income.

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  As of December 31, 2003 and 2002, the Company had equity investments in publicly traded securities classified as available-for-sale (included in other long term-assets) with an original cost to the Company of $585 and a fair value of approximately $2,367 and $1,300, respectively. As of December 31, 2003, the Company recorded an unrealized holding gain of $1,782, correspondingly $1,094 was recorded as a component of accumulated other comprehensive income and $688 was recorded as a decrease to the deferred tax asset. As of December 31, 2002, the Company recorded an unrealized holding gain of $715 of which $430 was recorded as a component of accumulated other comprehensive income and $285 was recorded as a deferred tax liability.

  Income Taxes—Prior to the Company’s initial public offering in November 2003, the Company was included in the consolidated federal income tax return of Alliant Energy but was treated as a separate entity for income tax purposes. The Company provides deferred federal and state income taxes on all temporary differences between the book and tax basis of the Company’s assets and liabilities.

  Earnings Per Share—Basic net income per common share of stock is calculated by dividing net income by the weighted average of common shares outstanding during each year. Diluted net income per common share of stock is calculated by dividing net income by the weighted average of common shares outstanding and other dilutive securities. There were no potentially dilutive securities of the Company outstanding for any of the periods presented.

  Industry Segment and Geographic Information—The Company operates in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of the Company’s operations are conducted in the United States. Consequently, the Company currently reports as a single industry segment.

  New Accounting Pronouncements—In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141, Business Combinations which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets, which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The Company did not change or reclassify contractual mineral rights included in oil and gas properties on the balance sheet upon adoption of SFAS No. 142. The Company believes the current accounting of such mineral rights as part of crude oil and natural gas properties is appropriate under the successful efforts method of accounting. However, there is an alternative view that reclassification of mineral rights to an intangible assets may be necessary. If a reclassification of contractual mineral rights acquired subsequent to July 1, 2001 from oil and gas properties to long term intangible assets is required, then the reclassified amount as of December 31, 2003 and 2002 would be approximately $160.1 million and $161.2 million, respectively. Management does not believe that the ultimate outcome of this issue will have a significant impact on the Company’s cash flows, results of operations or financial condition.

  In June 2002 the FASB issued SFAS No. 146, Accounting for Costs Associates with Exit or Disposal Activities. This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (“EITF”) Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. The adoption of this Statement had no impact on the financial statements.

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  FASB Interpretation No. 45 (FIN 45), Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others was issued in November 2002, by the FASB. FIN 45 requires a guarantor to recognize a liability for the fair value of the obligation it assumes under certain guarantees. Additionally, FIN 45 requires a guarantor to disclose certain aspects of each guarantee, or each group of similar guarantees, including the nature of the guarantee, the maximum exposure under the guarantee, the current carrying amount of any liability for the guarantee, and any recourse provisions allowing the guarantor to recover from third parties any amounts paid under the guarantee. The disclosure provisions of FIN 45 are effective for financial statements for both interim and annual periods ending after December 15, 2002. The fair value measurement provisions of FIN 45 are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The adoption of this Statement did not have a material impact on the financial statements. Under the disclosure provisions, the Company, as part of a 2002 purchase transaction, agreed to share with the seller 50% of the actual price received for certain crude oil production in excess of $19.00 per barrel. The agreement runs through December 31, 2009 and contains a 2% price escalation per year. As a result, the sharing amount at January 1, 2004 increased to 50% of the actual price received in excess of $19.77 per barrel. Approximately 46,000 net barrels of crude oil per month are subject to this sharing agreement. The terms of the agreement do not provide for a maximum amount to be paid. As of December 31, 2003, the Company has paid $3.1 million under this agreement and has accrued an additional $215 as currently payable.

  In January 2003, the FASB issued FASB Interpretation No. 46 (as revised in December 2003), Consolidation of Variable Interest Entities (FIN 46). FIN 46 clarifies the application of Accounting Research Bulletin No. 51, Consolidated Financial Statements to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated support from other parties. FIN 46 requires existing unconsolidated variable interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. All companies with interests in variable interest entities created after January 31, 2003, shall apply the provisions of FIN 46 to those entities immediately. The adoption of this Statement had no impact on the Company's financial statements.

  In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities to amend and clarify financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. The changes in this statement require that contracts with comparable characteristics be accounted for similarly to achieve more consistent reporting of contracts as either derivative or hybrid instruments. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003 and will be applied prospectively. The adoption of this Statement had no impact on the financial statements.

  In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity to classify certain financial instruments as liabilities in statements of financial position. The financial instruments are mandatorily redeemable shares, which the issuing company is obligated to buy back in exchange for cash or other assets, put options and forward purchase contracts, instruments that do or may require the issuer to buy back some of its shares in exchange for cash or other assets, and obligations that can be settled with shares, the monetary value of which is fixed, tied solely or predominantly to a variable such as a market index, or varies inversely with the value of the issuers’ shares. Most of the guidance in SFAS No. 150 is effective for all financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this Statement had no impact on the financial statements.

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2. ASSET RETIREMENT OBLIGATIONS

  The Company’s estimated liability for plugging and abandoning its oil and gas wells and certain obligations for previously owned onshore and offshore facilities in California is discounted using a credit-adjusted risk-free rate of approximately 7%. Upon adoption of SFAS No. 143, the Company recorded an increase to its discounted abandonment liability of $16.4 million, increased proved property cost by $10.1 million and recognized a one-time cumulative effect charge of $3.9 million (net of a deferred tax benefit of $2.4 million).

  The following table provides a reconciliation of the changes in the estimated asset retirement obligation from the amount recorded upon adoption of SFAS No. 143 on January 1, 2003 (including its previously recognized liability in California) through December 31, 2003.

Beginning asset retirement obligation     $ 4,232  
SFAS 143 adoption    16,458  
Additional liability incurred    996  
Accretion expense    1,482  
Liabilities settled    (147 )

Ending asset retirement obligation   $ 23,021  


  No revisions have been made to the timing or the amount of the original estimate of undiscounted cash flows during 2003.

3. INVESTMENT IN PARTNERSHIPS

  The Company sponsors private oil and gas income and development limited partnerships. The partnership agreements generally provide for a capital contribution by the Company of 8% to 10% of total capital for a 13% to 17% interest in the net revenue of the partnerships. Additionally, Whiting is a general partner in various partnerships which own and operate transportation and gas processing facilities. As a general partner in these partnerships, Whiting may be liable to the extent any such partnerships incur liabilities in excess of the value of its assets.

  In 2003, the Company purchased the limited partnership interests in three limited partnerships in which the Company was general partner for $4,453.

4. RELATED PARTY TRANSACTIONS

  In conjunction with the Company’s initial public offering in November 2003, the Company issued a promissory note payable to Alliant Energy in the aggregate principal amount of $3.0 million. The note bears interest at an annual rate of 5%. All principal and interest on the promissory note are due on November 25, 2005 (see Note 5).

  Alliant Energy had loaned the Company an aggregate $80.5 million as of December 31, 2002. The note bore interest at a floating rate which ranged from 6.9% to 4.4% during 2003 and 2002, respectively. On March 31, 2003, Alliant Energy converted its outstanding intercompany balance of $80,931 to equity of the Company. The Company incurred approximately $1.2 million, $10.5 million and $10.2 million, in interest expense related to this note during the years ended December 31, 2003, 2002 and 2001, respectively.

  The Company holds a 6% working interest in four federal offshore platforms and related onshore plant and equipment in California. Alliant Energy has guaranteed the Company’s obligation in the abandonment of these assets.

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  The Company provides general and administrative services to its partnerships for which the partnerships are billed monthly. Amounts so charged are based on flat rates provided for in each respective Partnership Agreement. The Company pays operating expenses for its partnerships for which it receives reimbursement. The Company may also advance funds to its partnerships for property development. The amounts due from/to affiliates represent the net amount of advances to partnerships for property development offset by proceeds on sales of property and cash receipts from the sale of oil and gas to be distributed to the partnerships.

5. LONG-TERM DEBT

  Long-term debt consisted of the following at December 31, 2003 and 2002:

2003
2002
Bank borrowings     $ 185,000   $ 185,000  
Alliant--see Note 4    3,017    80,472  

  Credit Facility— The Company has a $350.0 million credit agreement with a syndicate of banks. At December 31, 2003, the credit agreement provided a borrowing base of $210.0 million with an outstanding principal balance of $185.0 million. On February 17, 2004, the Company repaid $40.0 million of the outstanding principal balance from cash on hand in excess of projected drilling and production needs. The borrowing base under the credit agreement is based on the collateral value of the Company’s proved reserves and is subject to redetermination on May 1 and November 1 of each year. If the borrowing base is determined to be lower than the outstanding principal balance then drawn, the Company must immediately pay the difference. The credit agreement provides for interest only payments until December 20, 2005, when the entire amount borrowed is due. Interest accrues, at the Company’s option, at either (1) the base rate plus a margin where the base rate is defined as the higher of the federal funds rate plus 0.5% or the prime rate and the margin varies from 0.25% to 1.0% depending on the ratio of the amounts borrowed to the borrowing base, or (2) at the LIBOR rate plus a margin where the margin varies from 1.5% to 2.25% depending on the ratio of the amounts borrowed to the borrowing base. At December 31, 2003, all amounts outstanding under the credit agreement bore interest at an annual rate of 3.21% through February 6, 2004.

  On February 6, 2004, the Company fixed the rate on the outstanding principal balance at an annual rate of 3.2% through August 6, 2004. The credit agreement has covenants that restrict the payment of cash dividends, borrowings, sale of assets, loans to others, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders and requires the Company to maintain certain debt to EBITDAX (as defined in our credit agreement) ratios and a working capital ratio. The credit agreement also precludes the Company from providing any cash to Alliant Energy except for services rendered on an arm’s-length basis or for income taxes. The Company was in compliance with the covenants under the credit agreement as of December 31, 2003. The credit agreement is secured by a first lien on substantially all of Whiting’s assets.

6. EMPLOYEE BENEFIT PLANS

  The Company has a Production Participation Plan for all employees. On an annual basis, management and the Board of Directors allocate interests in oil and gas properties acquired or developed during the year to the plan on a discretionary basis. Once allocated, the interests (not legally conveyed) are fixed and plan participants generally vest ratably over five years. Forfeitures are re-allocated among other Plan participants. Allocations prior to 1995 consisted of 2% — 3% overriding royalty interests. Allocations since 1995 have been 2% — 5% net revenue interests.

  Payments to participants of the plan are made annually in cash after year end and amounted to $4.4 million, $3.6 million and $4.1 million for 2003, 2002 and 2001, respectively. The Company has estimated the total discounted obligations, including the amounts above, at December 31, 2003 and 2002 as being $12.3 million and $11.7 million, respectively. Plan expense for 2003, 2002 and 2001 was approximately $4.3 million, $5.3 million and $5.6 million, respectively.

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  The Company’s Board of Directors adopted the Whiting Petroleum Corporation 2003 Equity Incentive Plan on September 17, 2003. Two million shares of the Company’s common stock have been reserved for issuance under this plan. No participating employee may be granted options for more than 300,000 shares of common stock, stock appreciation rights with respect to more than 300,000 shares of common stock or more than 150,000 shares of restricted stock during any calendar year. This plan prohibits the repricing of outstanding stock options without stockholder approval. As of December 31, 2003, no awards had been made under this plan.

  The Company also had a phantom equity plan as an incentive to employees. The phantom equity plan award was calculated based on the growth of the Company’s proved oil and gas reserves before income taxes from January 1, 2000 to a triggering event, less increases in debt for the same period (the “Value Appreciation”). The Value Appreciation was then multiplied by a sharing percentage of 5%. The completion of the initial public offering in November 2003 constituted a triggering event under the plan and, consequently, the Company’s employees received a $10.9 million award in the form of approximately 420,000 shares of Whiting common stock after withholding of shares for payroll and income taxes. Alliant Energy was required to fund the majority of plan expense by contributing cash and stock to the Company in the combined amount of $10.7 million, which is reflected as an increase to additional paid-in capital. The phantom equity plan is now terminated.

  The Company also has a defined contribution retirement plan for all employees. The plan is funded by employee contributions and discretionary Company contributions. The Company’s contributions for 2003, 2002 and 2001 were approximately $665, $529 and $287, respectively. Employer contributions vest ratably at 20% per year over a five year period.

7. COMMITMENTS AND CONTINGENCIES

  The Company leases administrative office space under an operating lease arrangement through October 2005. Net rental expense for 2003, 2002, and 2001 amounted to approximately $1,046, $916 and $823, respectively. A summary of future minimum lease payments under this noncancellable-operating lease as of December 31, 2003 is as follows (in thousands):

Year Ending December 31        
2004   $ 1,084  
2005    929  

Total   $ 2,013  


  The Company had a $2.5 million unused line of credit with a bank. Interest on the line of credit was prime plus one percent. The line of credit was cancelled in February 2003.

  The Company is subject to litigation claims and governmental and regulatory controls arising in the ordinary course of business. It is the opinion of the Company’s management that all claims and litigation involving the Company are not likely to have a material adverse effect on its financial position or results of operations.

  Tax Separation and Indemnification Agreement with Alliant Energy—In connection with Whiting’s initial public offering in November 2003, the Company entered into a tax separation and indemnification agreement with Alliant Energy. Pursuant to this agreement, the Company and Alliant Energy made a tax election with the effect that the tax basis of the assets of Whiting and its subsidiaries were increased to the deemed purchase price of their assets immediately prior to such initial public offering. Whiting has adjusted deferred taxes on its balance sheet to reflect the new tax basis of the Company’s assets. This additional basis is expected to result in increased future income tax deductions and, accordingly, may reduce income taxes otherwise payable by Whiting. Under this agreement, the Company has agreed to pay to Alliant Energy 90% of the future tax benefits the Company realizes annually as a result of this step-up in tax basis for the years ending on or prior to December 31, 2013. Such tax benefits will generally be calculated by comparing the Company’s actual taxes to the taxes that would have been owed by the Company had the increase in basis not occurred. In 2014, Whiting will be obligated to pay Alliant Energy the present value of the remaining tax benefits assuming all such tax benefits will be realized in future years. Future tax benefits in total will approximate $62 million. The Company has estimated total payments to Alliant will approximate $49 million given the discounting affect of the final payment in 2014. The Company has discounted all cash payments to Alliant at the date of the Tax Separation Agreement.

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  The initial recording of this transaction in November 2003 resulted in a $57.2 million increase in deferred tax assets, a $28.6 million discounted payable to Alliant Energy and a $28.6 million increase to stockholders’ equity. The Company will monitor the estimate of when payments will be made and adjust the accretion of this liability on a prospective basis. There is a provision in the Tax Separation Agreement that if tax rates were to change (increase or decrease), the tax benefit or detriment would result in a corresponding adjustment of the Alliant liability. For purposes of this calculation, management has assumed that no such change will occur during the term of this agreement.

8. INCOME TAXES

  Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax bases of assets and liabilities and amounts reported in the Company’s balance sheet. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liability determines the periodic provision for deferred taxes.

  Prior to the Company’s initial public offering, the Company was included in the consolidated federal income tax return of Alliant Energy and calculated its income tax expense on a separate return basis at Alliant Energy’s effective tax rate less any research or Section 29 tax credits generated by the Company. Current tax due under this calculation was paid to Alliant Energy, and current refunds were received from Alliant Energy. All income taxes receivable or payable at December 31, 2003 were to/from Alliant Energy. Section 29 tax credits of $5,363 were generated in 2002 and are expected to be utilized by Alliant Energy in the future. However, on a stand-alone basis Whiting would have been unable to use the credits in its 2002 tax return. Under the Company’s tax separation and indemnification agreement with Alliant Energy, Whiting will be paid for the Section 29 credits when Alliant Energy receives the benefit for them. These credits were reported as a credit to additional paid-in capital in 2002.

  Income tax expense differed from amounts computed by applying the U.S. Federal income tax rate as follows (in thousands):

2003
2002
2001
Expected statutory tax expense at 35%     $ 12,649   $ 4,183   $ 19,018  
Research and Section 29 tax credits    --    (178 )  (6,575 )
Excess percentage depletion    (216 )  (82 )  (268 )
State tax expense, net of federal benefit    1,516    300    918  



    $ 13,949   $ 4,223   $ 13,093  






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  Temporary differences between the financial statement carrying amounts and tax bases of assets and liabilities that give rise to the net deferred tax asset or (liability) result from the following components (in thousands):

2003
2002
Oil and gas properties     $ (2,893 ) $ (32,290 )
Production participation plan    2,993    3,020  
Available for sale securities    (127 )  (285 )
Derivative instruments    828    1,320  
Tax sharing agreement    11,028    --  
Abandonment obligations    3,028    --  
Net operating loss carryforward    3,878    --  


    $ 18,735   $ (28,235 )



  The Company's net operating loss will expire in 2023.

9. OIL AND GAS ACTIVITIES

  The Company’s oil and gas activities are conducted entirely in the United States. Costs incurred in oil and gas producing activities are as follows (in thousands):

2003
2002
2001
Unproved property acquisition     $ 242   $ 851   $ 105  
Proved property acquisition    10,914    140,708    66,024  
Development    40,336    23,136    32,073  
Exploration    3,186    1,811    793  




Subtotal
    54,678    166,506    98,995  

Asset retirement obligations
    996    --    --  



Total   $ 55,674   $ 166,506   $ 98,995  




  During 2003, additions to oil and gas properties of approximately $996 were recorded for the estimated costs related to new wells drilled or acquired.

  Net capitalized costs related to the Company’s oil and gas producing activities are summarized as follows (in thousands):

2003
2002
Proven oil and gas properties     $ 615,764   $ 553,902  
Unproven oil and gas properties    1,637    1,593  
Accumulated depreciation, depletion and amortization    (191,488 )  (152,595 )



Oil and gas properties--net
   $ 425,913   $ 402,900  



  During 2003, the Company recorded an addition to oil and gas properties of approximately $10.1 million for the asset retirement costs related to the adoption of SFAS No. 143.

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10. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

  The estimate of proved reserves and related valuations were based upon the reports of Ryder Scott Company L.P., and Cawley, Gillespie & Associates, Inc. and R. A. Lenser & Associates, Inc., each independent petroleum and geological engineers, and the Company’s engineering staff, in accordance with the provisions of Statement of Financial Accounting Standards No. 69 (“SFAS No. 69”), Disclosures about Oil and Gas Producing Activities. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

  The Company’s oil and gas reserves are attributable solely to properties within the United States. A summary of the Company’s changes in quantities of proved oil and gas reserves for the years ended December 31, 2003, 2002 and 2001, are as follows:

Oil (Mbbls)
Gas (Mmcf)
Balance--January 1, 2001      19,121    157,521  
     Extensions and discoveries    1,086    9,320  
     Sales of minerals in place    (677 )  (6,045 )
     Purchases of minerals in place    945    89,760  
     Production    (2,088 )  (19,751 )
     Revisions to previous estimates    (3,582 )  (3,284 )


Balance--December 31, 2001    14,805    227,521  
     Extensions and discoveries    473    2,346  
     Sales of minerals in place         (953 )
     Purchases of minerals in place    15,244    58,381  
     Production    (2,319 )  (21,366 )
     Revisions to previous estimates    1,255    (29,941 )


Balance--December 31, 2002    29,458    235,988  
     Extensions and discoveries    2,327    17,097  
     Sales of minerals in place    --    --  
     Purchases of minerals in place    822    3,996  
     Production    (2,594 )  (21,596 )
     Revisions to previous estimates    4,627    (4,474 )


Balance--December 31, 2003    34,640    231,011  


Proved developed reserves:  
     December 31, 2001    11,046    136,817  


     December 31, 2002    23,784    167,618  


     December 31, 2003    26,157    171,881  



  As discussed in “Note 6—Employee Benefit Plans,” all of the Company’s employees participate in the Company’s production participation plan. The reserve disclosures above include oil and gas reserve volumes that have been allocated to the production participation plan. Once allocated to plan participants, the interests are fixed. Allocations prior to 1995 consisted of 2%–3% overriding royalty interest while allocations since 1995 have been 2%–5% of net income from the oil and gas production allocated to the plan.

50



  The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with the provisions of SFAS No. 69. Future cash inflows were computed by applying prices at year end to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at year end, based on year-end costs and assuming continuation of existing economic conditions.

  Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Company’s oil and gas properties.

  The standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows (in thousands):

2003
2002
2001
Future cash flows     $ 2,297,935   $ 1,854,886   $ 880,890  
Future production costs    (879,390 )  (677,146 )  (379,732 )
Future development costs    (66,326 )  (65,440 )  (75,575 )
Future income tax expense    (336,165 )  (270,516 )  (62,025 )



Future net cash flows    1,016,054    841,784    363,558  
10% annual discount for estimated timing of cash flows    (426,490 )  (365,755 )  (151,823 )



Standardized measure of discounted future net cash flows   $ 589,564   $ 476,029   $ 211,735  




  Future cash flows as shown above were reported without consideration for the effects of hedging transactions outstanding at each period end. If the effects of hedging transactions were included in the computation, then future cash flows would have decreased by $145 in 2003 and $1,300 in 2002 and $0 in 2001, respectively.

  The changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows (in thousands):

2003
2002
2001
    (in thousands)

Beginning of year:
    $ 476,029   $ 211,735   $ 519,197  
     Sale of oil and gas produced, net of production costs    (121,827 )  (80,337 )  (87,273 )
     Sales of minerals in place    --    (739 )  (11,200 )
     Net changes in prices and production costs    108,115    212,191    (528,096 )
     Extensions, discoveries and improved recoveries    47,183    6,587    17,511  
     Development costs-net    (886 )  (11,328 )  (3,322 )
     Purchases of mineral in place    16,745    241,798    84,613  
     Revisions of previous quantity estimates    43,679    (36,164 )  (16,205 )
     Net change in income taxes    (42,082 )  (116,854 )  183,051  
     Accretion of discount    62,901    24,786    73,516  
     Changes in production rates and other    (293 )  24,354    (20,057 )



End of year   $ 589,564   $ 476,029   $ 211,735  




51



  Average wellhead prices in effect at December 31, 2003, 2002 and 2001 inclusive of adjustments for quality and location used in determining future net revenues related to the standardized measure calculation are as follows (in thousands):

2003
2002
2001
Oil (per Bbl)     $ 29.43   $ 28.21   $ 17.30  
Gas (per Mcf)   $ 5.52   $ 4.39   $ 2.72  

11. QUARTERLY FINANCIAL DATA (UNAUDITED)

  The following is a summary of the unaudited financial data for each quarter for the years ended December 31, 2003, 2002, and 2001 (in thousands except per share data) (in thousands):

Three Months Ended
March 31,
2003

June 30,
2003

September 30,
2003

December 31,
2003

Year ended December 31, 2003:                    
Oil and gas sales   $ 49,483   $ 41,883   $ 42,272   $ 42,093  
Income (loss) before income tax and
   cumulative effect of change in
   accounting principle
    11,935    11,481    12,885    (162 )
Cumulative effect of change in
   accounting principle
    (3,905 )  --    --    --  
Net income (loss)    3,559    7,053    7,989    (316 )
Basic net income (loss) per share     0.19  0.38    0.43    (0.02 )

Three Months Ended
March 31,
2002

June 30,
2002

September 30,
2002

December 31,
2002

Year ended December 31, 2002:                    
Oil and gas sales   $ 20,190   $ 29,552   $ 34,657   $ 38,310  
Income (loss) before income tax    (2,977 )  3,277    6,191    5,461  
Net income    (1,822 )  2,050    3,877    3,624  
Basic net income (loss) per share    (0.10 )  0.11    0.21    0.19  

12. SUBSEQUENT EVENT

  On February 2, 2004, Whiting announced that the Company entered into a definitive merger agreement to acquire Equity Oil Company. The merger agreement provides for a stock-for-stock merger under which Equity shareholders will receive a fixed exchange ratio of 0.185 shares of Whiting common stock for each share of Equity common stock that they own. In addition, Whiting will assume approximately $29 million of Equity debt. The merger is subject to the approval of shareholders owning two-thirds of the outstanding Equity shares and other customary closing conditions. Equity intends to call a special meeting of its shareholders during the second quarter of 2004 to consider and vote on the merger. The Company expects to complete the merger as soon as practicable following approval by Equity’s shareholders.

******

52



Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

        None.

Item 9A. Controls and Procedures

        Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), our management evaluated, with the participation of our Chairman, President and Chief Executive Officer and our Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the year ended December 31, 2003. Based upon their evaluation of these disclosures controls and procedures, the Chairman, President and Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures were effective as of the end of the year ended December 31, 2003 to ensure that material information relating to us, including our consolidated subsidiaries, was made known to them by others within those entities, particularly during the period in which this Annual Report on Form 10-K was being prepared.

        Changes in internal control over financial reporting. There was no change in our internal control over financial reporting that occurred during the quarter ended December 31, 2003 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART III

Item 10. Directors and Executive Officers of the Registrant

        The information included under the captions “Election of Directors,” “Board of Directors and Corporate Governance” and “Section 16(a) Beneficial Ownership Reporting Compliance”, respectively, in our definitive Proxy Statement for Whiting Petroleum Corporation’s 2004 Annual Meeting of Stockholders (the “Proxy Statement”) is hereby incorporated herein by reference. Information with respect to our executive officers appears in Part I of this Annual Report on Form 10-K.

        We have adopted the Whiting Petroleum Corporation Code of Business Conduct and Ethics that applies to our directors, our Chairman, President and Chief Executive Officer, our Chief Financial Officer, our Controller and Treasurer and other persons performing similar functions. We have posted a copy of the Whiting Petroleum Corporation Code of Business Conduct and Ethics on our website at www.whiting.com. The Whiting Petroleum Corporation Code of Business Conduct and Ethics is also available in print to any stockholder who requests it in writing from the Corporate Secretary of Whiting Petroleum Corporation. We intend to satisfy the disclosure requirements under Item 10 of Form 8-K regarding amendments to, or waivers from, the Whiting Petroleum Corporation Code of Business Conduct and Ethics by posting such information on our website at www.whiting.com.

        We have also adopted corporate governance guidelines and written charters for our Audit, Compensation and Nominating and Governance Committees and have posted copies of those documents on our website at www.whiting.com. Copies of these documents are also available in print to any stockholder who requests them in writing from the Corporate Secretary of Whiting Petroleum Corporation.

        We are not including the information contained on our website as part of, or incorporating it by reference into, this report.

Item 11. Executive Compensation

        The information required by this Item is included under the captions “Board of Directors and Corporate Governance – Director Compensation” and “Executive Compensation” in the Proxy Statement and is hereby incorporated herein by reference.

53



Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

        The information required by this Item with respect to security ownership of certain beneficial owners and management is included under the caption “Principal Stockholders” in the Proxy Statement and is hereby incorporated by reference.

        The following table sets forth information with respect to compensation plans under which equity securities of Whiting Petroleum Corporation are authorized for issuance as of December 31, 2003.

Plan Category           
Number of securities
to be issued upon
the exercise of
outstanding options,
warrants and rights
Weighted-average
exercise price of
outstanding options,
warrants and rights
Number of securities remaining
available for future issuance
under equity compensation
plans (excluding securities
reflected in the first column)

Equity compensation plans approved                
  by security holders(1)     --    N/A    2,000,000  
Equity compensation plans not  
  approved by security holders    --    N/A    --  


     Total    --    N/a    2,000,000  


_____________
(1)    Includes only the Company's 2003 Equity Incentive Plan.

Item 13. Certain Relationships and Related Transactions

        Not applicable.

Item 14. Principal Accountant Fees and Services

        The information required by this Item is included under the caption “Ratification of Appointment of Independent Auditors” in the Proxy Statement and is hereby incorporated by reference.

PART IV

Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K

(a) 1. Financial statements – The following financial statements and the report of independent auditors are contained in Item 8.

  a. Independent Auditors' Report

  b. Consolidated Balance Sheets as of December 31, 2003 and 2002

  c. Consolidated Statements of Income for the Years ended December 31, 2003, 2002 and 2001

  d. Consolidated Statements of Stockholders’ Equity and Comprehensive Income for the Years ended December 31, 2003, 2002 and 2001

  e. Consolidated Statements of Cash Flows for the Years ended December 31, 2003, 2002 and 2001

  f. Notes to Consolidated Financial Statements


54




  2. Financial statement schedules – All schedules are omitted since the required information is not present, or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements and the notes thereto.

  3. Exhibits – The exhibits listed in the accompanying index to exhibits are filed as part of this Annual Report on Form 10-K.

(b) Reports on Form 8-K

  None.


















55


SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on this 4th day of March, 2004.

WHITING PETROLEUM CORPORATION


  By:    /s/  James J. Volker
James J. Volker
Chairman, President and Chief Executive Officer

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Name
Title
Date

/s/ James J. Volker

Chairman, President, Chief Executive Officer

March 4, 2004
James J. Volker and Director (Principal Executive Officer)

/s/ James R. Casperson
Chief Financial Officer March 4, 2004
James R. Casperson (Principal Financial Officer)

/s/ Michael J. Stevens
Controller and Treasurer March 4, 2004
Michael J. Stevens (Principal Accounting Officer)

/s/ Thomas L. Aller
Director March 4, 2004
Thomas L. Aller

/s/ Graydon D. Hubbard
Director March 4, 2004
Graydon D. Hubbard

/s/ J. B. Ladd
Director March 4, 2004
J. B. Ladd

/s/ Kenneth R. Whiting
Director March 4, 2004
Kenneth R. Whiting


56


EXHIBIT INDEX

Exhibit

Exhibit
Number

Exhibit Description

(2) Agreement and Plan of Merger, dated February 1, 2004, by and among Whiting Petroleum Corporation, WPC Equity Acquisition Corp. and Equity Oil Company. [Incorporated by reference to Exhibit 10.1 to Equity Oil Company’s Current Report on Form 8-K dated February 2, 2004 (File No. 000 00610)]. Schedules and exhibits to the Agreement and Plan of Merger have not been filed herewith. The registrant agrees to furnish a copy of any omitted schedule or exhibit to the Securities and Exchange Commission upon request.

(3.1) Amended and Restated Certificate of Incorporation of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 3.1 to Whiting Petroleum Corporation’s Registration Statement on Form S-1 (Registration No. 333-107341)].

(3.2) Amendment to Amended and Restated By-laws of Whiting Petroleum Corporation.

(4.1) Credit Agreement, dated as of December 20, 2002, among Whiting Oil and Gas Corporation (f/k/a Whiting Petroleum Corporation), the financial institutions listed therein, Bank One, NA, as Administrative Agent, and Wachovia Bank, N.A., as Syndication Agent [Incorporated by reference to Exhibit 10.5 to Alliant Energy Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 1-9894)].

(4.2) First Amendment to Credit Agreement, effective as of January 7, 2003, among Whiting Oil and Gas Corporation (f/k/a Whiting Petroleum Corporation), Bank One, NA, as Administrative Agent, and the financial institutions party thereto [Incorporated by reference to Exhibit 10.5a to Alliant Energy Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 1-9894)].

(4.3) Second Amendment to Credit Agreement, effective as of June 30, 2003, among Whiting Oil and Gas Corporation (f/k/a Whiting Petroleum Corporation), Bank One, NA, as Administrative Agent, and the financial institutions party thereto [Incorporated by reference to Exhibit 4.4 to Whiting Petroleum Corporation’s Registration Statement on Form S-1 (Registration No. 333-107341)].

(4.4) Third Amendment to Credit Agreement, dated as of October 24, 2003, among Whiting Oil and Gas Corporation, Bank One, NA, as Administrative Agent, and the financial institutions party thereto [Incorporated by reference to Exhibit 4.5 to Whiting Petroleum Corporation’s Registration Statement on Form S-1 (Registration No. 333-107341)].

(10.1)* Whiting Oil and Gas Corporation Phantom Equity Plan, as amended and restated [Incorporated by reference to Exhibit 10.10 to Whiting Petroleum Corporation’s Registration Statement on Form S-1 (Registration No. 333-107341)].

(10.2)* Whiting Petroleum Corporation 2003 Equity Incentive Plan [Incorporated by reference to Exhibit 10.11 to Whiting Petroleum Corporation's Registration Statement on Form S-1 (Registration No. 333-107341)].

(10.3)* Whiting Oil and Gas Corporation Production Participation Plan [Incorporated by reference to Exhibit 10.5 to Whiting Petroleum Corporation's Registration Statement on Form S-1 (Registration No. 333-107341)].


57



(10.4)* First Amendment to Whiting Oil and Gas Corporation Production Participation Plan [Incorporated by reference to Exhibit 10.6 to Whiting Petroleum Corporation's Registration Statement on Form S-1 (Registration No. 333-107341)].

(10.5)* Second Amendment to Whiting Oil and Gas Corporation Production Participation Plan [Incorporated by reference to Exhibit 10.7 to Whiting Petroleum Corporation's Registration Statement on Form S-1 (Registration No. 333-107341)].

(10.6)* Third Amendment to Whiting Oil and Gas Corporation Production Participation Plan [Incorporated by reference to Exhibit 10.8 to Whiting Petroleum Corporation's Registration Statement on Form S-1 (Registration No. 333-107341)].

(10.7)* Fourth Amendment to Whiting Oil and Gas Corporation Production Participation Plan [Incorporated by reference to Exhibit 10.9 to Whiting Petroleum Corporation's Registration Statement on Form S-1 (Registration No. 333-107341)].

(10.8) Master Separation Agreement among Alliant Energy Corporation, Alliant Energy Resources, Inc., Whiting Petroleum Corporation and Whiting Oil and Gas Corporation [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Registration Statement on Form S-1 (Registration No. 333-107341)].

(10.9) Registration Rights Agreement among Alliant Energy Corporation, Alliant Energy Resources, Inc. and Whiting Petroleum Corporation [Incorporated by reference to Exhibit 10.2 to Whiting Petroleum Corporation’s Registration Statement on Form S-1 (Registration No. 333-107341)].

(10.10) Tax Separation and Indemnification Agreement between Alliant Energy Corporation, Whiting Petroleum Corporation and Whiting Oil and Gas Corporation [Incorporated by reference to Exhibit 10.3 to Whiting Petroleum Corporation’s Registration Statement on Form S-1 (Registration No. 333-107341)].

(21) Subsidiaries of Whiting Petroleum Corporation.

(23.1) Consent of Deloitte & Touche LLP.

(23.2) Consent of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers.

(23.3) Consent of R.A. Lenser & Associates, Inc., Independent Petroleum Engineers.

(23.4) Consent of Ryder Scott Company, L.P., Independent Petroleum Engineers.

(31.1) Certification by Chairman, President and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

(31.2) Certification by the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

(32.1) Certification of the Chairman, President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350

(32.2) Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350


58




(99.1) Proxy Statement for the 2004 Annual Meeting of Stockholders, to be filed within 120 days of December 31, 2003 [To be filed with the Securities and Exchange Commission under Regulation 14A within 120 days after December 31, 2003; except to the extent specifically incorporated by reference, the Proxy Statement for the 2004 Annual Meeting of Stockholders shall not be deemed to be filed with the Securities and Exchange Commission as part of this Annual Report on Form 10-K]


*   A management contract or compensatory plan or arrangement.





















59

Exhibit 3.2

AMENDMENT TO AMENDED AND RESTATED BY-LAWS
OF WHITING PETROLEUM CORPORATION

        The following amendment to Whiting Petroleum Corporation’s Amended and Restated By-Laws was adopted by the Board of Directors of Whiting Petroleum Corporation on January 27, 2004:

        RESOLVED, that the first two sentences of Article III, Section 6 of the Corporation’s Amended and Restated By-Laws are hereby amended and restated to read in their entirety as follows:

  “No person who has attained seventy-five (75) years of age shall be eligible for election or re-election to the Board of Directors; provided, however, that J. B. Ladd and Kenneth R. Whiting shall be eligible for re-election to the Board of Directors until attaining ages 82 and 79, respectively. Any director who has attained seventy-five (75) years of age (or, in the case of the individuals specified in the prior sentence, the age specified in the prior sentence) shall resign from the Board of Directors effective as of the next Annual Meeting.”

***

        A complete copy of the Amended and Restated By-Laws of Whiting Petroleum Corporation as so amended is attached.


AMENDED AND RESTATED
BY-LAWS
OF
WHITING PETROLEUM CORPORATION

ARTICLE I

OFFICES

        Section 1.     Registered Office. The registered office of the Corporation shall be in the City of Wilmington, County of New Castle, State of Delaware.

        Section 2.     Other Offices. The Corporation may also have offices at such other places both within and without the State of Delaware as the Board of Directors may from time to time determine.

ARTICLE II

MEETINGS OF STOCKHOLDERS

        Section 1.     Place of Meetings. Meetings of the stockholders for the election of directors or for any other purpose shall be held at such time and place, either within or without the State of Delaware as shall be designated from time to time by the Board of Directors. The Board of Directors may, in its sole discretion, determine that a meeting of the stockholders shall not be held at any place, but may instead be held solely by means of remote communication in the manner authorized by the General Corporation Law of the State of Delaware (the “DGCL”).

        Section 2.     Annual Meetings. The annual meeting of the stockholders (the “Annual Meeting”) for the election of directors shall be held on such date and at such time as shall be designated from time to time by the Board of Directors. Any other proper business brought in accordance with Section 14 of this Article II may be transacted at the Annual Meeting.

        Section 3.     Special Meetings. Unless otherwise required by law or by the certificate of incorporation of the Corporation, as amended and restated from time to time (the “Certificate of Incorporation”), a special meeting of the stockholders (a “Special Meeting”), for any purpose or purposes, may be called only by (a) the Chairman of the Board of Directors, if there be one, (b) the President or (c) a majority of the entire Board of Directors. At a Special Meeting, only such business shall be conducted as shall be specified in the notice of meeting (or any supplement thereto) given by or at the direction of the Board of Directors.

        Section 4.     Notice. Whenever stockholders are required or permitted to take any action at a meeting, a written notice of the meeting, shall be given which shall state the place, if any, date and hour of the meeting, the means of remote communications, if any, by which stockholders and proxyholders may be deemed to be present in person and vote at such meeting, and, in the case of a Special Meeting, the purpose or purposes for which the meeting is called. Unless otherwise required by law, the written notice of any meeting shall be given not less than ten nor more than sixty days before the date of the meeting to each stockholder entitled to vote at such meeting.


        Section 5.     Adjournments. Any meeting of the stockholders may be adjourned from time to time to reconvene at the same or some other place, and notice need not be given of any such adjourned meeting if the time and place, if any, thereof and the means of remote communications, if any, by which stockholders and proxyholders may be deemed to be present in person and vote at such adjourned meeting are announced at the meeting at which the adjournment is taken. At the adjourned meeting, the Corporation may transact any business which might have been transacted at the original meeting. If the adjournment is for more than thirty days, or if after the adjournment a new record date is fixed for the adjourned meeting, notice of the adjourned meeting in accordance with the requirements of Section 4 of this Article II shall be given to each stockholder of record entitled to vote at the meeting.

        Section 6.     Quorum. Unless otherwise required by applicable law or the Certificate of Incorporation, the holders of a majority of the Corporation’s capital stock issued and outstanding and entitled to vote thereat, present in person or represented by proxy, shall constitute a quorum at all meetings of the stockholders for the transaction of business. A quorum, once established, shall not be broken by the withdrawal of enough votes to leave less than a quorum. If, however, such quorum shall not be present or represented at any meeting of the stockholders, the stockholders entitled to vote thereat, present in person or represented by proxy, shall have power to adjourn the meeting from time to time, in the manner provided in Section 5 of this Article II, until a quorum shall be present or represented.

        Section 7.     Voting. Unless otherwise required by law, the Certificate of Incorporation or these By-laws, any question brought before any meeting of stockholders, other than the election of directors, shall be decided by the vote of the holders of a majority of the total number of votes of the Corporation’s capital stock represented and entitled to vote thereat, voting as a single class. Unless otherwise provided in the Certificate of Incorporation, and subject to Section 10 of this Article II, each stockholder represented at a meeting of stockholders shall be entitled to cast one vote for each share of the capital stock entitled to vote thereat held by such stockholder. Such votes may be cast in person or by proxy as provided in Section 8 of this Article II but no proxy shall be voted on or after three years from its date, unless such proxy provides for a longer period. The Board of Directors, in its discretion, or the officer of the Corporation presiding at a meeting of stockholders, in such officer’s discretion, may require that any votes cast at such meeting shall be cast by written ballot.

        Section 8.     Proxies. Each stockholder entitled to vote at a meeting of the stockholders may authorize another person or persons to act for such stockholder as proxy, but no such proxy shall be voted upon after three years from its date, unless such proxy provides for a longer period. Without limiting the manner in which a stockholder may authorize another person or persons to act for such stockholder as proxy, the following shall constitute a valid means by which a stockholder may grant such authority:

                     (a)     A stockholder may execute a writing authorizing another person or persons to act for such stockholder as proxy. Execution may be accomplished by the stockholder or such stockholder’s authorized officer, director, employee or agent signing such writing or causing such person’s signature to be affixed to such writing by any reasonable means, including, but not limited to, by facsimile signature.

2


                     (b)     A stockholder may authorize another person or persons to act for such stockholder as proxy by transmitting or authorizing the transmission of a telegram, cablegram or other means of electronic transmission to the person who will be the holder of the proxy or to a proxy solicitation firm, proxy support service organization or like agent duly authorized by the person who will be the holder of the proxy to receive such transmission, provided that any such telegram, cablegram or other means of electronic transmission must either set forth or be submitted with information from which it can be determined that the telegram, cablegram or other electronic transmission was authorized by the stockholder. If it is determined that such telegrams, cablegrams or other electronic transmissions are valid, the inspectors, or if there are no inspectors, such other persons making that determination shall specify the information on which they relied.

        Any copy, facsimile telecommunication or other reliable reproduction of the writing or transmission authorizing another person or persons to act as proxy for a stockholder may be substituted or used in lieu of the original writing or transmission for any and all purposes for which the original writing or transmission could be used; provided, however, that such copy, facsimile telecommunication or other reproduction shall be a complete reproduction of the entire original writing or transmission.

        Section 9.     List of Stockholders Entitled to Vote. The officer of the Corporation who has charge of the stock ledger of the Corporation shall prepare and make, at least ten days before every meeting of stockholders, a complete list of the stockholders entitled to vote at the meeting, arranged in alphabetical order, and showing the address of each stockholder and the number of shares registered in the name of each stockholder. Such list shall be open to the examination of any stockholder, for any purpose germane to the meeting, during ordinary business hours, for a period of at least ten days prior to the meeting (a) on a reasonably accessible electronic network, provided that the information required to gain access to such list is provided with the notice of the meeting, or (b) at the principal place of business of the Corporation. In the event that the Corporation determines to make the list available on an electronic network, the Corporation may take reasonable steps to ensure that such information is available only to stockholders of the Corporation. If the meeting is to be held at a place, then the list shall be produced and kept at the time and place of the meeting during the whole time thereof, and may be inspected by any stockholder of the Corporation who is present. If the meeting is to be held solely by means of remote communication then the list shall also be open to the examination of any stockholder during the whole time of the meeting on a reasonably accessible electronic network, and the information required to access such list shall be provided with the notice of the meeting.

        Section 10.     Record Date. In order that the Corporation may determine the stockholders entitled to notice of or to vote at any meeting of the stockholders or any adjournment thereof, the Board of Directors may fix a record date, which record date shall not precede the date upon which the resolution fixing the record date is adopted by the Board of Directors, and which record date shall not be more than sixty nor less than ten days before the date of such meeting. If no record date is fixed by the Board of Directors, the record date for determining stockholders entitled to notice of or to vote at a meeting of the stockholders shall be at the close of business on the day next preceding the date on which notice is given, or, if notice is waived, at the close of business on the next preceding the day on which the meeting is held. A determination of stockholders of record entitled to notice of or to vote at a meeting of the stockholders shall apply to any adjournment of the meeting; provided, however, that the Board of Directors may fix a new record date for the adjourned meeting.

3


        Section 11.     Stock Ledger. The stock ledger of the Corporation shall be the only evidence as to who are the stockholders entitled to examine the stock ledger, the list required by Section 9 of this Article II or the books of the Corporation, or to vote in person or by proxy at any meeting of stockholders.

        Section 12.     Conduct of Meetings. The Board of Directors of the Corporation may adopt by resolution such rules and regulations for the conduct of the meeting of the stockholders as it shall deem appropriate. Except to the extent inconsistent with such rules and regulations as adopted by the Board of Directors, the chairman of any meeting of the stockholders shall have the right and authority to prescribe such rules, regulations and procedures and to do all such acts as, in the judgment of such chairman, are appropriate for the proper conduct of the meeting. Such rules, regulations or procedures, whether adopted by the Board of Directors or prescribed by the chairman of the meeting, may include, without limitation, the following: (a) the establishment of an agenda or order of business for the meeting; (b) the determination of when the polls shall open and close for any given matter to be voted on at the meeting; (c) rules and procedures for maintaining order at the meeting and the safety of those present; (d) limitations on attendance at or participation in the meeting to stockholders of record of the corporation, their duly authorized and constituted proxies or such other persons as the chairman of the meeting shall determine; (e) restrictions on entry to the meeting after the time fixed for the commencement thereof; and (f) limitations on the time allotted to questions or comments by participants.

        Section 13.     Inspectors of Election. In advance of any meeting of the stockholders, the Board of Directors, by resolution, the Chairman or the President shall appoint one or more inspectors to act at the meeting and make a written report thereof. One or more persons may be designated as alternate inspectors to replace any inspector who fails to act. If no inspector or alternate is able to act at a meeting of the stockholders, the Chairman of the meeting shall appoint one or more inspectors to act at the meeting. Unless otherwise required by applicable law, inspectors may be officers, employees or agents of the Corporation. Each inspector, before entering upon the discharge of the duties of inspector, shall take and sign an oath faithfully to execute the duties of inspector with strict impartiality and according to the best of such inspector’s ability. The inspector shall have the duties prescribed by law and shall take charge of the polls and, when the vote is completed, shall make a certificate of the result of the vote taken and such other facts as may be required by applicable law.

        Section 14.     Nature of Business at Meetings of Stockholders. No business may be transacted at an Annual Meeting, other than business that is either (a) specified in the notice of meeting (or any supplement thereto) given by or at the direction of the Board of Directors (or any duly authorized committee thereof), (b) otherwise properly brought before the Annual Meeting by or at the direction of the Board of Directors (or any duly authorized committee thereof) or (c) otherwise properly brought before the Annual Meeting by any stockholder of the Corporation (i) who is a stockholder of record on the date of the giving of the notice provided for in this Section 14 and on the record date for the determination of stockholders entitled to vote at such Annual Meeting and (ii) who complies with the notice procedures set forth in this Section 14.

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        In addition to any other applicable requirements, for business to be properly brought before an Annual Meeting by a stockholder, such stockholder must have given timely notice thereof in proper written form to the Secretary of the Corporation.

        To be timely, a stockholder’s notice to the Secretary must be delivered to or mailed and received at the principal executive offices of the Corporation not less than sixty days nor more than ninety days prior to the anniversary date of the immediately preceding Annual Meeting; provided, however, that in the event that the Annual Meeting is called for a date that is not within thirty days before or after such anniversary date, notice by the stockholder in order to be timely must be so received not later than the close of business on the tenth day following the day on which such notice of the date of the Annual Meeting was mailed or such public disclosure of the date of the Annual Meeting was made, whichever first occurs.

        To be in proper written form, a stockholder’s notice to the Secretary must set forth as to each matter such stockholder proposes to bring before the Annual Meeting (a) a brief description of the business desired to be brought before the Annual Meeting and the reasons for conducting such business at the Annual Meeting, (b) the name and record address of such stockholder, (c) the class or series and number of shares of capital stock of the Corporation which are owned beneficially or of record by such stockholder, (d) a description of all arrangements or understandings between such stockholder and any other person or persons (including their names) in connection with the proposal of such business by such stockholder and any material interest of such stockholder in such business and (e) a representation that such stockholder intends to appear in person or by proxy at the Annual Meeting to bring such business before the meeting.

        No business shall be conducted at the Annual Meeting except business brought before the Annual Meeting in accordance with the procedures set forth in this Section 14; provided, however, that, once business has been properly brought before the Annual Meeting in accordance with such procedures, nothing in this Section 14 shall be deemed to preclude discussion by any stockholder of any such business. If the Chairman of an Annual Meeting determines that business was not properly brought before the Annual Meeting in accordance with the foregoing procedures, the Chairman shall declare to the meeting that the business was not properly brought before the meeting and such business shall not be transacted.

        Section 15.     Nomination of Directors. Only persons who are nominated in accordance with the following procedures shall be eligible for election as directors of the Corporation, except as may be otherwise provided in the Certificate of Incorporation with respect to the right of holders of preferred stock of the Corporation to nominate and elect a specified number of directors in certain circumstances. Nominations of persons for election to the Board of Directors may be made at any Annual Meeting, or at any Special Meeting called for the purpose of electing directors, (a) by or at the direction of the Board of Directors (or any duly authorized committee thereof) or (b) by any stockholder of the Corporation (i) who is a stockholder of record on the date of the giving of the notice provided for in this Section 15 and on the record date for the determination of stockholders entitled to vote at such meeting and (ii) who complies with the notice procedures set forth in this Section 15.

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        In addition to any other applicable requirements, for a nomination to be made by a stockholder, such stockholder must have given timely notice thereof in proper written form to the Secretary of the Corporation.

        To be timely, a stockholder’s notice to the Secretary must be delivered to or mailed and received at the principal executive offices of the Corporation (a) in the case of an Annual Meeting, not less than sixty days nor more than ninety days prior to the anniversary date of the immediately preceding Annual Meeting; provided, however, that in the event that the Annual Meeting is called for a date that is not within thirty days before or after such anniversary date, notice by the stockholder in order to be timely must be so received not later than the close of business on the tenth day following the day on which such notice of the date of the Annual Meeting was mailed or such public disclosure of the date of the Annual Meeting was made, whichever first occurs; and (b) in the case of a Special Meeting called for the purpose of electing directors, not later than the close of business on the tenth day following the day on which notice of the date of the Special Meeting was mailed or public disclosure of the date of the Special Meeting was made, whichever first occurs.

        To be in proper written form, a stockholder’s notice to the Secretary must set forth (a) as to each person whom the stockholder proposes to nominate for election as a director (i) the name, age, business address and residence address of the person, (ii) the principal occupation or employment of the person, (iii) the class or series and number of shares of capital stock of the Corporation which are owned beneficially or of record by the person and (iv) any other information relating to the person that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors pursuant to Section 14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the rules and regulations promulgated thereunder; and (b) as to the stockholder giving the notice (i) the name and record address of such stockholder, (ii) the class or series and number of shares of capital stock of the Corporation which are owned beneficially or of record by such stockholder, (iii) a description of all arrangements or understandings between such stockholder and each proposed nominee and any other person or persons (including their names) pursuant to which the nomination(s) are to be made by such stockholder, (iv) a representation that such stockholder intends to appear in person or by proxy at the meeting to nominate the persons named in its notice and (v) any other information relating to such stockholder that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors pursuant to Section 14 of the Exchange Act and the rules and regulations promulgated thereunder. Such notice must be accompanied by a written consent of each proposed nominee to being named as a nominee and to serve as a director if elected.

        No person shall be eligible for election as a director of the Corporation unless nominated in accordance with the procedures set forth in this Section 15. If the Chairman of the meeting determines that a nomination was not made in accordance with the foregoing procedures, the Chairman shall declare to the meeting that the nomination was defective and such defective nomination shall be disregarded.

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ARTICLE III

DIRECTORS

        Section 1.     Number and Election of Directors. The entire Board of Directors shall consist of not less than one nor more than twelve members, the exact number of which shall be determined from time to time exclusively by resolution adopted by the Board of Directors. The directors shall be divided into three classes, designated Class I, Class II and Class III. Each class shall consist, as nearly as may be possible, of one-third of the total number of directors constituting the entire Board of Directors. The initial division of the Board of Directors into classes shall be made by the decision of the affirmative vote of a majority of the entire Board of Directors. The term of the initial Class I directors shall terminate on the date of the 2004 Annual Meeting; the term of the initial Class II directors shall terminate on the date of the 2005 Annual Meeting; and the term of the initial Class III directors shall terminate on the date of the 2006 Annual Meeting. At each succeeding Annual Meeting beginning in 2004, successors to the class of directors whose term expires at that Annual Meeting shall be elected for a three-year term. If the number of directors is changed, any increase or decrease shall be apportioned among the classes so as to maintain the number of directors in each class as nearly equal as possible, and any additional director of any class elected to fill a vacancy resulting from an increase in such class shall hold office for a term that shall coincide with the remaining term of that class, but in no case will a decrease in the number of directors shorten the term of any incumbent director. Except as provided in Section 2 of this Article III, directors shall be elected by the stockholders at the Annual Meetings, and each director so elected shall hold office until such director’s successor is duly elected and qualified, or until such director’s death, or until such director’s earlier resignation or removal. Directors need not be stockholders.

        Section 2.     Vacancies. Unless otherwise required by law or the Certificate of Incorporation, vacancies arising through death, resignation, removal, an increase in the number of directors or otherwise may be filled only by a majority of the directors then in office, though less than a quorum, or by a sole remaining director, and the directors so chosen shall hold office until the next annual election and until their successors are duly elected and qualified, or until their earlier death, resignation or removal.

        Section 3.     Duties and Powers. The business and affairs of the Corporation shall be managed by or under the direction of the Board of Directors which may exercise all such powers of the Corporation and do all such lawful acts and things as are not by statute or by the Certificate of Incorporation or by these By-Laws required to be exercised or done by the stockholders.

        Section 4.     Meetings. The Board of Directors may hold meetings, both regular and special, either within or without the State of Delaware. Regular meetings of the Board of Directors may be held without notice at such time and at such place as may from time to time be determined by the Board of Directors. Special meetings of the Board of Directors may be called by the Chairman of the Board of Directors, if there be one, the President or a majority of the directors then in office. Notice thereof stating the place, date and hour of the meeting shall be given to each director either by mail not less than forty-eight hours before the date of the meeting, by telephone or telegram or electronic means on twenty-four hours’ notice, or on such shorter notice as the person or persons calling such meeting may deem necessary or appropriate in the circumstances.

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        Section 5.     Organization. At each meeting of the Board of Directors, the Chairman of the Board of Directors, or, in his or her absence, a director chosen by a majority of the directors present, shall act as chairman. The Secretary of the Corporation shall act as secretary at each meeting of the Board of Directors. In case the Secretary shall be absent from any meeting of the Board of Directors, an Assistant Secretary shall perform the duties of secretary at such meeting; and in the absence from any such meeting of the Secretary and all the Assistant Secretaries, the chairman of the meeting may appoint any person to act as secretary of the meeting.

        Section 6.     Term, Resignation and Removal of Directors. No person who has attained seventy-five (75) years of age shall be eligible for election or re-election to the Board of Directors; provided, however, that J. B. Ladd and Kenneth R. Whiting shall be eligible for re-election to the Board of Directors until attaining ages 82 and 79, respectively. Any director who has attained seventy-five (75) years of age (or, in the case of the individuals specified in the prior sentence, the age specified in the prior sentence) shall resign from the Board of Directors effective as of the next Annual Meeting. Any director of the Corporation may resign at any time, by giving notice in writing or by electronic transmission to the Chairman of the Board of Directors, the President or the Secretary of the Corporation. Such resignation shall take effect at the time therein specified or, if no time is specified, immediately; and, unless otherwise specified in such notice, the acceptance of such resignation shall not be necessary to make it effective. If any director of the Corporation experiences a material change in employment status (including termination of employment, retirement or a material decrease in job responsibilities) from that when the director was most recently elected to the Board of Directors, then such director shall be deemed to have automatically tendered his or her resignation as a director of the Corporation, which may be accepted by the remainder of the Board of Directors, in its sole discretion, and, if so accepted, shall be effective as of such acceptance. Except as otherwise required by applicable law, any director or the entire Board of Directors may be removed from office at any time, but only for cause, by the affirmative vote of the holders of at least seventy percent in voting power of the issued and outstanding capital stock of the Corporation entitled to vote in the election of directors.

        Section 7.     Quorum. Except as otherwise required by law or the Certificate of Incorporation, at all meetings of the Board of Directors, a majority of the entire Board of Directors shall constitute a quorum for the transaction of business and the act of a majority of the directors present at any meeting at which there is a quorum shall be the act of the Board of Directors. If a quorum shall not be present at any meeting of the Board of Directors, the directors present thereat may adjourn the meeting from time to time, without notice other than announcement at the meeting of the time and place of the adjourned meeting, until a quorum shall be present.

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        Section 8.     Actions of the Board by Written Consent. Unless otherwise provided in the Certificate of Incorporation or these By-Laws, any action required or permitted to be taken at any meeting of the Board of Directors or of any committee thereof may be taken without a meeting, if all the members of the Board of Directors or committee, as the case may be, consent thereto in writing or by electronic transmission, and the writing or writings or electronic transmission or transmissions are filed with the minutes of proceedings of the Board of Directors or committee. Such filing shall be in paper form if the minutes are maintained in paper form and shall be in electronic form if the minutes are maintained in electronic form.

        Section 9.     Meetings by Means of Conference Telephone. Unless otherwise provided in the Certificate of Incorporation or these By-Laws, members of the Board of Directors of the Corporation, or any committee thereof, may participate in a meeting of the Board of Directors or such committee by means of a conference telephone or similar communications equipment by means of which all persons participating in the meeting can hear each other, and participation in a meeting pursuant to this Section 9 shall constitute presence in person at such meeting.

        Section 10.     Committees. The Board of Directors may designate one or more committees, each committee to consist of one or more of the directors of the Corporation. The Board of Directors may designate one or more directors as alternate members of any committee, who may replace any absent or disqualified member at any meeting of any such committee. In the absence or disqualification of a member of a committee, and in the absence of a designation by the Board of Directors of an alternate member to replace the absent or disqualified member, the member or members thereof present at any meeting and not disqualified from voting, whether or not such member or members constitute a quorum, may unanimously appoint another member of the Board of Directors to act at the meeting in the place of any absent or disqualified member. Any committee, to the extent permitted by law and provided in the resolution establishing such committee, shall have and may exercise all the powers and authority of the Board of Directors in the management of the business and affairs of the Corporation. Each committee shall keep regular minutes and report to the Board of Directors when required.

        Section 11.     Compensation. The directors may be paid their expenses, if any, of attendance at each meeting of the Board of Directors and may be paid a fixed sum for attendance at each meeting of the Board of Directors or a stated salary for service as director, payable in cash or securities. No such payment shall preclude any director from serving the Corporation in any other capacity and receiving compensation therefor. Members of special or standing committees may be allowed like compensation for attending committee meetings.

        Section 12.     Interested Directors. No contract or transaction between the Corporation and one or more of its directors or officers, or between the Corporation and any other corporation, partnership, association, or other organization in which one or more of its directors or officers are directors or officers or have a financial interest, shall be void or voidable solely for this reason, or solely because the director or officer is present at or participates in the meeting of the Board of Directors or committee thereof which authorizes the contract or transaction, or solely because the director or officer’s vote is counted for such purpose if (a) the material facts as to the director or officer’s relationship or interest and as to the contract or transaction are disclosed or are known to the Board of Directors or the committee, and the Board of Directors or committee in good faith authorizes the contract or transaction by the affirmative votes of a majority of the disinterested directors, even though the disinterested directors be less than a quorum; or (b) the material facts as to the director or officer’s relationship or interest and as to the contract or transaction are disclosed or are known to the stockholders entitled to vote thereon, and the contract or transaction is specifically approved in good faith by vote of the stockholders; or (c) the contract or transaction is fair as to the Corporation as of the time it is authorized, approved or ratified by the Board of Directors, a committee thereof or the stockholders. Common or interested directors may be counted in determining the presence of a quorum at a meeting of the Board of Directors or of a committee which authorizes the contract or transaction.

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ARTICLE IV

OFFICERS

        Section 1.     General. The officers of the Corporation shall be chosen by the Board of Directors and shall be a President, a Secretary and a Treasurer. The Board of Directors, in its discretion, also may choose a Chairman of the Board of Directors (who must be a director) and one or more Vice Presidents, Assistant Secretaries, Assistant Treasurers and other officers. Any number of offices may be held by the same person, unless otherwise prohibited by law or the Certificate of Incorporation or these By-Laws. The officers of the Corporation need not be stockholders of the Corporation nor, except in the case of the Chairman of the Board of Directors, need such officers be directors of the Corporation.

        Section 2.     Election. The Board of Directors, at its first meeting held after each Annual Meeting of Stockholders, shall elect the officers of the Corporation who shall hold their offices for such terms and shall exercise such powers and perform such duties as shall be determined from time to time by the Board of Directors; and all officers of the Corporation shall hold office until their successors are chosen and qualified, or until their earlier death, resignation or removal. Any officer elected by the Board of Directors may be removed at any time by the affirmative vote of the Board of Directors. Any vacancy occurring in any office of the Corporation shall be filled by the Board of Directors.

        Section 3.     Voting Securities Owned by the Corporation. Powers of attorney, proxies, waivers of notice of meeting, consents and other instruments relating to securities owned by the Corporation may be executed in the name of and on behalf of the Corporation by the President or any Vice President or any other officer authorized to do so by the Board of Directors and any such officer may, in the name of and on behalf of the Corporation, take all such action as any such officer may deem advisable to vote in person or by proxy at any meeting of security holders of any corporation in which the Corporation may own securities and at any such meeting shall possess and may exercise any and all rights and power incident to the ownership of such securities and which, as the owner thereof, the Corporation might have exercised and possessed if present. The Board of Directors may, by resolution, from time to time confer like powers upon any other person or persons.

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        Section 4.     Chairman of the Board of Directors. The Chairman of the Board of Directors, if there be one, shall preside at all meetings of the stockholders and of the Board of Directors. The Chairman of the Board of Directors shall be the Chief Executive Officer of the Corporation, unless the Board of Directors designates the President as the Chief Executive Officer, and, except where by law the signature of the President is required, the Chairman of the Board of Directors shall possess the same power as the President to sign all contracts, certificates and other instruments of the Corporation which may be authorized by the Board of Directors. During the absence or disability of the President, the Chairman of the Board of Directors shall exercise all the powers and discharge all the duties of the President. The Chairman of the Board of Directors shall also perform such other duties and may exercise such other powers as may from time to time be assigned by these By-Laws or by the Board of Directors.

        Section 5.     President. The President shall, subject to the control of the Board of Directors and, if there be one, the Chairman of the Board of Directors, have general supervision of the business of the Corporation and shall see that all orders and resolutions of the Board of Directors are carried into effect. The President shall execute all bonds, mortgages, contracts and other instruments of the Corporation except where required or permitted by law to be otherwise signed and executed and except that the other officers of the Corporation may sign and execute documents when so authorized by these By-Laws, the Board of Directors or the President. In the absence or disability of the Chairman of the Board of Directors, or if there be none, the President shall preside at all meetings of the stockholders and, provided the President is also a director, the Board of Directors. If there be no Chairman of the Board of Directors, or if the Board of Directors shall otherwise designate, the President shall be the Chief Executive Officer of the Corporation. The President shall also perform such other duties and may exercise such other powers as may from time to time be assigned to such officer by these By-Laws or by the Board of Directors.

        Section 6.     Vice Presidents. At the request of the President or in the President’s absence or in the event of the President’s inability or refusal to act (and if there be no Chairman of the Board of Directors), the Vice President, or the Vice Presidents if there is more than one (in the order designated by the Board of Directors), shall perform the duties of the President, and when so acting, shall have all the powers of and be subject to all the restrictions upon the President. Each Vice President shall perform such other duties and have such other powers as the Board of Directors from time to time may prescribe. If there be no Chairman of the Board of Directors and no Vice President, the Board of Directors shall designate the officer of the Corporation who, in the absence of the President or in the event of the inability or refusal of the President to act, shall perform the duties of the President, and when so acting, shall have all the powers of and be subject to all the restrictions upon the President.

        Section 7.     Secretary. The Secretary shall attend all meetings of the Board of Directors and all meetings of stockholders and record all the proceedings thereat in a book or books to be kept for that purpose; the Secretary shall also perform like duties for committees of the Board of Directors when required. The Secretary shall give, or cause to be given, notice of all meetings of the stockholders and special meetings of the Board of Directors, and shall perform such other duties as may be prescribed by the Board of Directors, the Chairman of the Board of Directors or the President, under whose supervision the Secretary shall be. If the Secretary shall be unable or shall refuse to cause to be given notice of all meetings of the stockholders and special meetings of the Board of Directors, and if there be no Assistant Secretary, then either the Board of Directors or the President may choose another officer to cause such notice to be given. The Secretary shall see that all books, reports, statements, certificates and other documents and records required by law to be kept or filed are properly kept or filed, as the case may be.

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        Section 8.     Treasurer. The Treasurer shall have the custody of the corporate funds and securities and shall keep full and accurate accounts of receipts and disbursements in books belonging to the Corporation and shall deposit all moneys and other valuable effects in the name and to the credit of the Corporation in such depositories as may be designated by the Board of Directors. The Treasurer shall disburse the funds of the Corporation as may be ordered by the Board of Directors, taking proper vouchers for such disbursements, and shall render to the President and the Board of Directors, at its regular meetings, or when the Board of Directors so requires, an account of all transactions as Treasurer and of the financial condition of the Corporation. If required by the Board of Directors, the Treasurer shall give the Corporation a bond in such sum and with such surety or sureties as shall be satisfactory to the Board of Directors for the faithful performance of the duties of the office of the Treasurer and for the restoration to the Corporation, in case of the Treasurer’s death, resignation, retirement or removal from office, of all books, papers, vouchers, money and other property of whatever kind in the Treasurer’s possession or under the Treasurer’s control belonging to the Corporation.

        Section 9.     Assistant Secretaries. Assistant Secretaries, if there be any, shall perform such duties and have such powers as from time to time may be assigned to them by the Board of Directors, the President, any Vice President, if there be one, or the Secretary, and in the absence of the Secretary or in the event of the Secretary’s disability or refusal to act, shall perform the duties of the Secretary, and when so acting, shall have all the powers of and be subject to all the restrictions upon the Secretary.

        Section 10.     Assistant Treasurers. Assistant Treasurers, if there be any, shall perform such duties and have such powers as from time to time may be assigned to them by the Board of Directors, the President, any Vice President, if there be one, or the Treasurer, and in the absence of the Treasurer or in the event of the Treasurer’s disability or refusal to act, shall perform the duties of the Treasurer, and when so acting, shall have all the powers of and be subject to all the restrictions upon the Treasurer. If required by the Board of Directors, an Assistant Treasurer shall give the Corporation a bond in such sum and with such surety or sureties as shall be satisfactory to the Board of Directors for the faithful performance of the duties of the office of Assistant Treasurer and for the restoration to the Corporation, in case of the Assistant Treasurer’s death, resignation, retirement or removal from office, of all books, papers, vouchers, money and other property of whatever kind in the Assistant Treasurer’s possession or under the Assistant Treasurer’s control belonging to the Corporation.

        Section 11.     Other Officers. Such other officers as the Board of Directors may choose shall perform such duties and have such powers as from time to time may be assigned to them by the Board of Directors. The Board of Directors may delegate to any other officer of the Corporation the power to choose such other officers and to prescribe their respective duties and powers.

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ARTICLE V

STOCK

        Section 1.     Form of Certificates. Every holder of stock in the Corporation shall be entitled to have a certificate signed by, or in the name of the Corporation (a) by the Chairman of the Board of Directors, the President or a Vice President and (b) by the Treasurer or an Assistant Treasurer, or the Secretary or an Assistant Secretary of the Corporation, certifying the number of shares owned by such stockholder in the Corporation.

        Section 2.     Signatures. Any or all of the signatures on a certificate may be a facsimile. In case any officer, transfer agent or registrar who has signed or whose facsimile signature has been placed upon a certificate shall have ceased to be such officer, transfer agent or registrar before such certificate is issued, it may be issued by the Corporation with the same effect as if such person were such officer, transfer agent or registrar at the date of issue.

        Section 3.     Lost Certificates. The Board of Directors may direct a new certificate to be issued in place of any certificate theretofore issued by the Corporation alleged to have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the person claiming the certificate of stock to be lost, stolen or destroyed. When authorizing such issue of a new certificate, the Board of Directors may, in its discretion and as a condition precedent to the issuance thereof, require the owner of such lost, stolen or destroyed certificate, or the owner’s legal representative, to advertise the same in such manner as the Board of Directors shall require and/or to give the Corporation a bond in such sum as it may direct as indemnity against any claim that may be made against the Corporation with respect to the certificate alleged to have been lost, stolen or destroyed or the issuance of such new certificate.

        Section 4.     Transfers. Stock of the Corporation shall be transferable in the manner prescribed by applicable law and in these By-Laws. Transfers of stock shall be made on the books of the Corporation only by the person named in the certificate or by such person’s attorney lawfully constituted in writing and upon the surrender of the certificate therefor, properly endorsed for transfer and payment of all necessary transfer taxes; provided however, that such surrender and endorsement or payment of taxes shall not be required in any case in which the officers of the corporation shall determine to waive such requirement. Every certificate exchanged, returned or surrendered to the Corporation shall be marked “cancelled” with the date of cancellation, by the Secretary of the Corporation or the transfer agent thereof. No transfer of stock shall be valid as against the Corporation for any purpose until it shall have been entered in the stock records of the Corporation by an entry showing from and to whom transferred.

        Section 5.     Dividend Record Date. In order that the Corporation may determine the stockholders entitled to receive payment of any dividend or other distribution or allotment of any rights or the stockholders entitled to exercise any rights in respect of any change, conversion or exchange of stock, or for the purpose of any other lawful action, the Board of Directors may fix a record date, which record date shall not precede the date upon which the resolution fixing the record date is adopted, and which record date shall be not more than sixty days prior to such action. If no record date is fixed, the record date for determining stockholders for any such purpose shall be at the close of business on the day on which the Board of Directors adopts the resolution relating thereto.

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        Section 6.     Record Owners. The Corporation shall be entitled to recognize the exclusive right of a person registered on its books as the owner of shares to receive dividends, and to vote as such owner, and to hold liable for calls and assessments a person registered on its books as the owner of shares, and shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise required by law.

        Section 7.     Transfer and Registry Agents. The Corporation may from time to time maintain one or more transfer offices or agencies and registry offices or agencies at such place or places as may be determined from time to time by the Board of Directors.

ARTICLE VI

NOTICES

        Section 1.     Notices. Whenever written notice is required by law, the Certificate of Incorporation or these By-Laws, to be given to any director, member of a committee or stockholder, such notice may be given by mail, addressed to such director, member of a committee or stockholder, at such person’s address as it appears on the records of the Corporation, with postage thereon prepaid, and such notice shall be deemed to be given at the time when the same shall be deposited in the United States mail. Without limiting the manner by which notice otherwise may be given effectively to stockholders, any notice to stockholders given by the Corporation under applicable law, the Certificate of Incorporation or these By-Laws shall be effective if given by a form of electronic transmission if consented to by the stockholder to whom the notice is given. Any such consent shall be revocable by the stockholder by written notice to the Corporation. Any such consent shall be deemed to be revoked if (a) the Corporation is unable to deliver by electronic transmission two consecutive notices by the Corporation in accordance with such consent and (b) such inability becomes known to the Secretary or Assistant Secretary of the Corporation or to the transfer agent, or other person responsible for the giving of notice; provided, however, that the inadvertent failure to treat such inability as a revocation shall not invalidate any meeting or other action. Notice given by electronic transmission, as described above, shall be deemed given: (a) if by facsimile telecommunication, when directed to a number at which the stockholder has consented to receive notice; (b) if by electronic mail, when directed to an electronic mail, at which the stockholder has consented to receive notice; (c) if by a posting on an electronic network, together with separate notice to the stockholder of such specific posting, upon the later of (i) such posting and (ii) the giving of such separate notice; and (d) if by any other form of electronic transmission, when directed to the stockholder. Notice to directors or committee members may also be given personally by telegram, telex or cable or by means of electronic transmission.

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        Section 2.     Waivers of Notice. Whenever any notice is required by applicable law, the Certificate of Incorporation or these By-Laws, to be given to any director, member of a committee or stockholder, a waiver thereof in writing, signed by the person or persons entitled to notice, or a waiver by electronic transmission, by the person or persons entitled to said notice, whether before or after the time stated therein, shall be deemed equivalent thereto. Attendance of a person at a meeting, present in person or represented by proxy, shall constitute a waiver of notice of such meeting, except where the person attends the meeting for the express purpose of objecting at the beginning of the meeting to the transaction of any business because the meeting is not lawfully called or convened. Neither the business to be transacted at, nor the purpose of, any Annual or Special Meeting of Stockholders or any regular or special meeting of the directors or members of a committee of directors need be specified in any written waiver of notice unless so required by law, the Certificate of Incorporation or these By-Laws.

ARTICLE VII

GENERAL PROVISIONS

        Section 1.     Dividends. Dividends upon the capital stock of the Corporation, subject to the requirements of the DGCL and the provisions of the Certificate of Incorporation, if any, may be declared by the Board of Directors at any regular or special meeting of the Board of Directors (or any action by written consent in lieu thereof in accordance with Section 8 of Article III hereof), and may be paid in cash, in property, or in shares of the Corporation’s capital stock. Before payment of any dividend, there may be set aside out of any funds of the Corporation available for dividends such sum or sums as the Board of Directors from time to time, in its absolute discretion, deems proper as a reserve or reserves to meet contingencies, or for purchasing any of the shares of capital stock, warrants, rights, options, bond, debentures, notes, scrip or other securities or evidences of indebtedness of the Corporation, or for equalizing dividends, or for repairing or maintaining any property of the Corporation, or for any proper purpose, and the Board of Directors may modify or abolish any such reserve.

        Section 2.     Disbursements. All checks or demands for money and notes of the Corporation shall be signed by such officer or officers or such other person or persons as the Board of Directors may from time to time designate.

        Section 3.     Fiscal Year. The fiscal year of the Corporation shall be fixed by resolution of the Board of Directors.

        Section 4.     Corporate Seal. The Corporation shall not be required to have a corporate seal.

ARTICLE VIII

INDEMNIFICATION

        Section 1.     Power to Indemnify in Actions, Suits or Proceedings other than Those by or in the Right of the Corporation. Subject to Section 3 of this Article VIII, the Corporation shall indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the Corporation) by reason of the fact that such person is or was a director or officer of the Corporation, or is or was a director or officer of the Corporation serving at the request of the Corporation as a director or officer, employee or agent of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with such action, suit or proceeding if such person acted in good faith and in a manner such person reasonably believed to be in or not opposed to the best interests of the Corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe such person’s conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction, or upon a plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that the person did not act in good faith and in a manner which such person reasonably believed to be in or not opposed to the best interests of the Corporation, and, with respect to any criminal action or proceeding, had reasonable cause to believe that such person’s conduct was unlawful.

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        Section 2.     Power to Indemnify in Actions, Suits or Proceedings by or in the Right of the Corporation. Subject to Section 3 of this Article VIII, the Corporation shall indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the Corporation to procure a judgment in its favor by reason of the fact that such person is or was a director or officer of the Corporation, or is or was a director or officer of the Corporation serving at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise against expenses (including attorneys’ fees) actually and reasonably incurred by such person in connection with the defense or settlement of such action or suit if such person acted in good faith and in a manner such person reasonably believed to be in or not opposed to the best interests of the Corporation; except that no indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the Corporation unless and only to the extent that the Court of Chancery of the State of Delaware or the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Court of Chancery or such other court shall deem proper.

        Section 3.     Authorization of Indemnification. Any indemnification under this Article VIII (unless ordered by a court) shall be made by the Corporation only as authorized in the specific case upon a determination that indemnification of the present or former director or officer is proper in the circumstances because such person has met the applicable standard of conduct set forth in Section 1 or Section 2 of this Article VIII, as the case may be. Such determination shall be made, with respect to a person who is a director or officer at the time of such determination, (a) by a majority vote of the directors who are not parties to such action, suit or proceeding, even though less than a quorum, or (b) by a committee of such directors designated by a majority vote of such directors, even though less than a quorum, or (c) if there are no such directors, or if such directors so direct, by independent legal counsel in a written opinion or (d) by the stockholders. Such determination shall be made, with respect to former directors and officers, by any person or persons having the authority to act on the matter on behalf of the Corporation. To the extent, however, that a present or former director or officer of the Corporation has been successful on the merits or otherwise in defense of any action, suit or proceeding described above, or in defense of any claim, issue or matter therein, such person shall be indemnified against expenses (including attorneys’ fees) actually and reasonably incurred by such person in connection therewith, without the necessity of authorization in the specific case.

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        Section 4.     Good Faith Defined. For purposes of any determination under Section 3 of this Article VIII, a person shall be deemed to have acted in good faith and in a manner such person reasonably believed to be in or not opposed to the best interests of the Corporation, or, with respect to any criminal action or proceeding, to have had no reasonable cause to believe such person’s conduct was unlawful, if such person’s action is based on the records or books of account of the Corporation or another enterprise, or on information supplied to such person by the officers of the Corporation or another enterprise in the course of their duties, or on the advice of legal counsel for the Corporation or another enterprise or on information or records given or reports made to the Corporation or another enterprise by an independent certified public accountant or by an appraiser or other expert selected with reasonable care by the Corporation or another enterprise. The provisions of this Section 4 shall not be deemed to be exclusive or to limit in any way the circumstances in which a person may be deemed to have met the applicable standard of conduct set forth in Section 1 or Section 2 of this Article VIII, as the case may be.

        Section 5.     Indemnification by a Court. Notwithstanding any contrary determination in the specific case under Section 3 of this Article VIII, and notwithstanding the absence of any determination thereunder, any director or officer may apply to the Court of Chancery of the State of Delaware or any other court of competent jurisdiction in the State of Delaware for indemnification to the extent otherwise permissible under Sections 1 and 2 of this Article VIII. The basis of such indemnification by a court shall be a determination by such court that indemnification of the director or officer is proper in the circumstances because such person has met the applicable standards of conduct set forth in Section 1 or Section 2 of this Article VIII, as the case may be. Neither a contrary determination in the specific case under Section 3 of this Article VIII nor the absence of any determination thereunder shall be a defense to such application or create a presumption that the director or officer seeking indemnification has not met any applicable standard of conduct. Notice of any application for indemnification pursuant to this Section 5 shall be given to the Corporation promptly upon the filing of such application. If successful, in whole or in part, the director or officer seeking indemnification shall also be entitled to be paid the expense of prosecuting such application.

        Section 6.     Expenses Payable in Advance. Expenses incurred by a director or officer in defending any civil, criminal, administrative or investigative action, suit or proceeding shall be paid by the Corporation in advance of the final disposition of such action, suit or proceeding upon receipt of an undertaking by or on behalf of such director or officer to repay such amount if it shall ultimately be determined that such person is not entitled to be indemnified by the Corporation as authorized in this Article VIII. Such expenses (including attorneys’ fees) incurred by former directors and officers or other employees and agents may be so paid upon such terms and conditions, if any, as the Corporation deems appropriate.

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        Section 7.     Nonexclusivity of Indemnification and Advancement of Expenses. The indemnification and advancement of expenses provided by or granted pursuant to this Article VIII shall not be deemed exclusive of any other rights to which those seeking indemnification or advancement of expenses may be entitled under the Certificate of Incorporation, any By-Law, agreement, vote of stockholders or disinterested directors or otherwise, both as to action in such person’s official capacity and as to action in another capacity while holding such office, it being the policy of the Corporation that indemnification of the persons specified in Section 1 and Section 2 of this Article VIII shall be made to the fullest extent permitted by law. The provisions of this Article VIII shall not be deemed to preclude the indemnification of any person who is not specified in Section 1 or Section 2 of this Article VIII but whom the Corporation has the power or obligation to indemnify under the provisions of the DGCL, or otherwise.

        Section 8.     Insurance. The Corporation may purchase and maintain insurance on behalf of any person who is or was a director or officer of the Corporation, or is or was a director or officer of the Corporation serving at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise against any liability asserted against such person and incurred by such person in any such capacity, or arising out of such person’s status as such, whether or not the Corporation would have the power or the obligation to indemnify such person against such liability under the provisions of this Article VIII.

        Section 9.     Certain Definitions. For purposes of this Article VIII, references to “the Corporation” shall include, in addition to the resulting corporation, any constituent corporation (including any constituent of a constituent) absorbed in a consolidation or merger which, if its separate existence had continued, would have had power and authority to indemnify its directors or officers, so that any person who is or was a director or officer of such constituent corporation, or is or was a director or officer of such constituent corporation serving at the request of such constituent corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, shall stand in the same position under the provisions of this Article VIII with respect to the resulting or surviving corporation as such person would have with respect to such constituent corporation if its separate existence had continued. The term “another enterprise” as used in this Article VIII shall mean any other corporation or any partnership, joint venture, trust, employee benefit plan or other enterprise of which such person is or was serving at the request of the Corporation as a director, officer, employee or agent. For purposes of this Article VIII, references to “fines” shall include any excise taxes assessed on a person with respect to an employee benefit plan; and references to “serving at the request of the Corporation” shall include any service as a director, officer, employee or agent of the Corporation which imposes duties on, or involves services by, such director or officer with respect to an employee benefit plan, its participants or beneficiaries; and a person who acted in good faith and in a manner such person reasonably believed to be in the interest of the participants and beneficiaries of an employee benefit plan shall be deemed to have acted in a manner “not opposed to the best interests of the Corporation”as referred to in this Article VIII.

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        Section 10.     Survival of Indemnification and Advancement of Expenses. The indemnification and advancement of expenses provided by, or granted pursuant to, this Article VIII shall, unless otherwise provided when authorized or ratified, continue as to a person who has ceased to be a director or officer and shall inure to the benefit of the heirs, executors and administrators of such a person.

        Section 11.     Limitation on Indemnification. Notwithstanding anything contained in this Article VIII to the contrary, except for proceedings to enforce rights to indemnification (which shall be governed by Section 5 of this Article VIII), the Corporation shall not be obligated to indemnify any director or officer (or his or her heirs, executors or personal or legal representatives) or advance expenses in connection with a proceeding (or part thereof) initiated by such person unless such proceeding (or part thereof) was authorized or consented to by the Board of Directors of the Corporation.

        Section 12.     Indemnification of Employees and Agents. The Corporation may, to the extent authorized from time to time by the Board of Directors, provide rights to indemnification and to the advancement of expenses to employees and agents of the Corporation similar to those conferred in this Article VIII to directors and officers of the Corporation.

ARTICLE IX

AMENDMENTS

        Section 1.     Amendments. In furtherance and not in limitation of the powers conferred upon it by the laws of the State of Delaware, the Board of Directors shall have the power to adopt, amend, alter or repeal the Corporation’s By-Laws. The affirmative vote of at least a majority of the entire Board of Directors shall be required to adopt, amend, alter or repeal the Corporation’s By-Laws. The Corporation’s By-Laws also may be adopted, amended, altered or repealed by the affirmative vote of the holders of at least seventy percent of the voting power of the shares entitled to vote at an election of directors.

        Section 2.     Entire Board of Directors. As used in this Article IX and in these By-Laws generally, the term “entire Board of Directors” means the total number of directors which the Corporation would have if there were no vacancies.

***

Last amended as of January 27, 2004.






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Exhibit 21

SUBSIDIARIES OF WHITING PETROLEUM CORPORATION

Name
Jurisdiction of
Incorporation or
Organization

Percent Ownership
Whiting Oil and Gas Corporation     Delaware     100 %
Whiting Programs, Inc.   Delaware   100 %
Whiting-Golden Gas Production Company   Oklahoma   100 %
WOK Acquisition Company   Delaware   100 %
Whiting 1985 Production Partnership, Ltd.   Texas   100 %
Whiting-State Street Production Partnership, Ltd.   Texas   100 %
Whiting-FBC Production Partnership, Ltd.   Texas   100 %
Whiting-High Street Production Partnership, Ltd.   Texas   100 %
Whiting-Park Production Partnership, Ltd.   Texas   16 %
Whiting-Madison Production Partnership, Ltd.   Texas   16 %
Whiting 1988 Production Limited Partnership, Ltd.   Texas   13 %










Exhibit 23.1



INDEPENDENT AUDITORS’ CONSENT


We consent to the incorporation by reference in Registration Statements Nos. 333-111055 and 333-111056 of Whiting Petroleum Corporation on Forms S-8 of our report dated February 25, 2004 (which report expresses an unqualified opinion and includes an explanatory paragraph referring to a change in Whiting Petroleum Corporation’s method of accounting for asset retirement obligations effective January 1, 2003), appearing in this Annual Report on Form 10-K of Whiting Petroleum Corporation for the year ended December 31, 2003.


/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
March 4, 2004

Exhibit 23.2



[CAWLEY, GILLESPIE & ASSOCIATES, INC. LETTERHEAD]

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS


        The undersigned hereby consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of Whiting Petroleum Corporation for the year ended December 31, 2003. We hereby further consent to the use of information contained in our report setting forth the estimates of revenues from Whiting Petroleum Corporation’s oil and gas reserves as of January 1, 2004. We further consent to the incorporation by reference thereof into Whiting Petroleum Corporation’s Registration Statements on Form S-8 (Registration Nos. 333-111055 and 333-111056).


Sincerely,



Date:  February 27, 2004 By:    /s/  Cawley, Gillespie & Associates, Inc.
Cawley, Gillespie & Associates, Inc.

Exhibit 23.3



[R.A. LENSER AND ASSOCIATES, INC. LETTERHEAD]

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS


        The undersigned hereby consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of Whiting Petroleum Corporation for the year ended December 31, 2003. We hereby further consent to the use of information contained in our report setting forth the estimates of revenues from Whiting Petroleum Corporation’s oil and gas reserves as of January 1, 2004. We further consent to the incorporation by reference thereof into Whiting Petroleum Corporation’s Registration Statements on Form S-8 (Registration Nos. 333-111055 and 333-111056).


Very truly yours,


Date:  February 27, 2004 By:    /s/  Ronald A. Lenser
R.A. Lenser & Associates, Inc.

Exhibit 23.4



[RYDER SCOTT COMPANY, L.P. LETTERHEAD]

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

        The undersigned hereby consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of Whiting Petroleum Corporation for the year ended December 31, 2003. We hereby further consent to the use of information contained in our report setting forth the estimates of revenues from Whiting Petroleum Corporation’s oil and gas reserves as of January 1, 2004. We further consent to the incorporation by reference thereof into Whiting Petroleum Corporation’s Registration Statements on Form S-8 (Registration Nos. 333-111055 and 333-111056).


Very truly yours,


Date:  February 27, 2004 By:    /s/  Ryder Scott Company, L.P.
Ryder Scott Company, L.P.

Exhibit 31.1

CERTIFICATIONS

I, James J. Volker, Chairman, President and Chief Executive Officer of Whiting Petroleum Corporation, certify that:

1. I have reviewed this Annual Report on Form 10-K of Whiting Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

  a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

  b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

  c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

  a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

  b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  March 4, 2004



/s/ James J. Volker

James J. Volker
Chairman, President and Chief Executive Officer

Exhibit 31.2

CERTIFICATIONS

I, James R. Casperson, Chief Financial Officer of Whiting Petroleum Corporation, certify that:

1. I have reviewed this Annual Report on Form 10-K of Whiting Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

  a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

  b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

  c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

  a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

  b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  March 4, 2004



/s/ James R. Casperson

James R. Casperson
Chief Financial Officer

Exhibit 32.1

Written Statement of the Chief Executive Officer
Pursuant to 18 U.S.C. Section 1350

        Solely for the purposes of complying with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, I, the undersigned Chairman, President and Chief Executive Officer of Whiting Petroleum Corporation, a Delaware corporation (the “Company”), hereby certify, based on my knowledge, that the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 2003 (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and that information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



/s/ James J. Volker

James J. Volker
Chairman, President and Chief Executive Officer

Date:  March 4, 2004

Exhibit 32.2

Written Statement of the Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350

        Solely for the purposes of complying with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, I, the undersigned Chief Financial Officer of Whiting Petroleum Corporation, a Delaware corporation (the “Company”), hereby certify, based on my knowledge, that the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 2003 (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and that information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



/s/ James R. Casperson

James R. Casperson
Chief Financial Officer

Date:  March 4, 2004