UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2005

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

For the transition period from                     to                    

Whiting Petroleum Corporation

(Exact name of registrant as specified in its charter)

Delaware		20-0098515
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
1700 Broadway, Suite 2300 Denver, Colorado		80290-2300
(Address of principal executive offices)		(Zip code)

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

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

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

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

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

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

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

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

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

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

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

Aggregate market value of the voting common stock held by non-affiliates of the registrant at June 30, 2005: $1,077,254,303.

Number of shares of the registrant’s common stock outstanding at February 15, 2006: 36,840,633 shares.

DOCUMENTS INCORPORATED BY REFERENCE

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

 

 

TABLE OF CONTENTS

Certain Definitions			2
PART I
Item 1. Business			4
Item 1A. Risk Factors			13
Item 1B. Unresolved Staff Comments			21
Item 2. Properties			21
Item 3. Legal Proceedings			26
Item 4. Submission of Matters to a Vote of Security Holders			26
Executive Officers of the Registrant			26
PART II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			28
Item 6. Selected Financial Data			29
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			31
Item 7A. Quantitative and Qualitative Disclosure About Market Risk			45
Item 8. Financial Statements and Supplementary Data			48
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			78
Item 9A. Controls and Procedures			78
Item 9B. Other Information			78
PART III
Item 10. Directors and Executive Officers of the Registrant			78
Item 11. Executive Compensation			79
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			79
Item 13. Certain Relationships and Related Transactions			79
Item 14. Principal Accountant Fees and Services			79
PART IV
Item 15. Exhibits, Financial Statement Schedules			80
Statement Re: Computation of Ratio of Earnings to Combined Fixed Charges
Subsidiaries of the Registrant
Consent of Deloitte & Touche LLP
Consent of Cawley, Gillespie & Associates, Inc.
Consent of R.A. Lenser & Associates, Inc.
Consent of Ryder Scott Company, L.P.
Consent of Netherland, Sewell & Associates, Inc.
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to 18 U.S.C. Section 1350
Certification Pursuant to 18 U.S.C. Section 1350

CERTAIN DEFINITIONS

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

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

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

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

     “Bcf” One billion cubic feet of natural gas.

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

     “BOE/d” One BOE per day.

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

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

     “frac” The process of creating a hydraulic fracture by pumping fluid down an oil or natural gas well at high pressures for short periods of time. The hydraulic fracture allows hydrocarbons to move more freely through the rocks in which they are trapped.

     “MBOE” One thousand BOE.

     “MBOE/d” One thousand BOE per day

     “Mcf” One thousand cubic feet of natural gas.

     “Mcf/d” One Mcf per day.

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

     “MMBOE” One million BOE.

     “MMbtu” One million British Thermal Units.

     “MMcf” One million cubic feet of natural gas.

     “MMcf/d” One thousand Mcf per day.

     “NGLs” Natural gas liquids.

     “PDNP” Proved developed nonproducing.

     “PDP” Proved developed producing.

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

     “PUD” Proved undeveloped.

     “pre-tax PV10%” The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated lease operating expense, production taxes and future development costs, using price and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or Federal income taxes and discounted using an annual discount rate of 10%. Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the Securities and Exchange Commission. See footnote (2) to the Proved Reserves table in “Business Overview” for more information.

     “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 to share in production, subject to all royalties, overriding royalties and other burdens and to share in all costs of exploration, development and operations and all risks in connection therewith.

PART I

Item 1.     Business

Overview

     We are an independent oil and natural gas company engaged in exploitation, acquisition, exploration and production activities primarily in the Permian Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the United States.

     Since our inception in 1980, we have built a strong asset base and achieved steady growth through both property acquisitions and exploitation activities. During 2005, we completed four separate acquisitions of producing properties for an aggregate purchase price of $897.7 million. The proved reserves of the acquired properties were estimated to be approximately 133.7 MMBOE as of the acquisition effective dates, representing an average cost of $6.71 per BOE of estimated proved reserves acquired. As of December 31, 2005, our estimated proved reserves totaled 263.6 MMBOE, representing an 83% increase in our proved reserves since December 31, 2004. Our estimated December 2005 average daily production was 40.7 MBOE/d, representing a 30% increase over our December 2004 average daily production and implying an average reserve life of approximately 17.7 years.

     The following table summarizes our estimated proved reserves by core area, the corresponding pre-tax PV10% value, our standardized measure of discounted future net cash flows as of December 31, 2005, and our December 2005 average daily production.

		Proved Reserves																				December 2005
																		Pre-Tax				Average Daily
		Oil				Natural				Total								PV10%				Production
Core Area		(MMbbl)				Gas (Bcf)				(MMBOE)				% Oil				Value(2)				(MBOE/d)
																		(In millions)
Permian Basin			105.8				84.5				119.9				88	%		$	1,621.3				12.7
Rocky Mountains(1)			40.7				105.5				58.3				70	%		$	964.4				11.9
Mid-Continent			46.6				41.9				53.6				87	%		$	859.1				5.4
Gulf Coast			4.2				83.8				18.2				23	%		$	473.2				7.8
Michigan			1.9				70.7				13.6				14	%		$	269.5				2.9
Total			199.2				386.4				263.6				76	%		$	4,187.5				40.7
Discounted Future Income Taxes			—				—				—				—		(	$	1,304.6	)			—
Standardized Measure of Discounted Future Net Cash Flows			—				—				—				—			$	2,882.9				—

     We expect to continue to build on our successful acquisition track record and seek property acquisitions that complement our existing core properties. Additionally, we believe that our significant drilling inventory, combined with our operating experience and efficient cost structure, provides us with significant organic growth opportunities. During 2005, we incurred $1.2 billion in acquisition, exploration and development activities, including $223.6 million for the drilling of 308 gross (180.5 net) wells. Of these new wells, 283 resulted in productive completions and 25 were unsuccessful, yielding a 92% success rate. We have budgeted approximately $360.0 million for development and exploration drilling expenditures in 2006. Based on current availability and access to drilling rigs in our areas of operations, we do not anticipate significant delays due to rig availability during 2006.

Celero Acquisitions

     In 2005, we acquired from Celero Energy, LP (“Celero”) the operated interests in two producing oil and natural gas fields as well as positions in several other smaller fields, totaling 122.3 MMBOE of estimated proved reserves as of the effective date of the acquisitions. On August 4, 2005, we acquired properties in the Postle field, located in the Oklahoma Panhandle, and on October 4, 2005, we acquired properties in the North Ward Estes field and certain other smaller fields, located in the Permian Basin.

     The effective date of both acquisitions was July 1, 2005. The total purchase price was $802.2 million comprised of $343.0 million in cash paid at the closing of the Postle properties and $442.0 million in cash paid at the closing of the North Ward Estes properties along with 441,500 shares of our common stock. We funded the acquisition of the Postle properties through borrowings under the credit agreement of Whiting Oil and Gas Corporation, our wholly-owned subsidiary. We funded the acquisition of the North Ward Estes properties with the net proceeds from the private placement of our 7% Senior Subordinated Notes due 2014 and our common stock offering, both of which closed on October 4, 2005.

Other 2005 Acquisitions

     Limited Partnerships Interests. On June 23, 2005, we completed our acquisition of all of the limited partnership interests in three institutional partnerships managed by our wholly-owned subsidiary Whiting Programs, Inc. The purchase price was $30.5 million for estimated proved reserves of approximately 2.9 MMBOE as of the acquisition effective date, resulting in a cost of $10.52 per BOE of estimated proved reserves. The partnership properties are located in Louisiana, Texas, Arkansas, Oklahoma and Wyoming. The average daily production from the properties was 0.7 MBOE/d as of the effective date of the acquisition. We funded the acquisition using cash on hand.

     Green River Basin. On March 31, 2005, we completed our acquisition of operated interests in five producing natural gas fields in the Green River Basin of Wyoming. The purchase price was $65.0 million for estimated proved reserves of approximately 8.4 MMBOE as of the acquisition effective date, resulting in a cost of $7.74 per BOE of estimated proved reserves. We operate approximately 95% of the average daily production from the properties, which was 1.1 MBOE/d as of the effective date of the acquisition. We funded the acquisition through borrowings under Whiting Oil and Gas Corporation’s credit agreement.

Business Strategy

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

     Developing and Exploiting Existing Properties. Our existing property base and our acquisitions over the past two years have provided us with significant low-risk opportunities for exploitation and development drilling. As of December 31, 2005, we have identified a drilling inventory of approximately 1,400 gross wells that we believe will add substantial production over the next five years. Our drilling inventory consists largely of the development of our proved undeveloped reserves on which we have spent significant time evaluating the costs and expected results. Additionally, we have several opportunities to apply enhanced recovery techniques that we expect will increase proved reserves and extend the productive lives of our mature fields. We anticipate significant increases in production from the Celero properties through the use of secondary and tertiary recovery techniques, including water and CO₂ floods.

     Growing Through Accretive Acquisitions. Since our initial public offering in November 2003, we have announced eleven acquisitions totaling 206.3 MMBOE of estimated total proved reserves. Our experienced team of management, engineering and geoscience professionals has developed and refined an acquisition program designed to increase reserves and complement our existing properties, including identifying and evaluating acquisition opportunities, negotiating and closing purchases, and managing acquired properties. As a result of our disciplined approach, we have achieved significant growth in our core areas at an average cost of $6.94 per BOE of proved reserves through these eleven acquisitions.

     Pursuing High-Return Organic Reserve Additions. We plan to allocate approximately 55% of our $360.0 million capital budget for 2006 to the development of our existing proved reserves. The remaining 45% will be invested in higher risk drilling, including field extensions drilled outside the current limits of our development projects as well as new exploration, which we believe will add substantially to our proved reserves and future cash flow. Although exploration has not been the most significant driver of our growth, we believe that we can prudently and successfully grow in part through exploratory activities given our technical team’s experience with advanced drilling techniques and our expanded base of operations. We own interests in approximately 615,500 gross (354,200 net) undeveloped acres as well as additional rights to deeper horizons within many of our developed acreage positions.

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

Competitive Strengths

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

     Balanced, Long-Lived Asset Base. As of December 31, 2005, we had interests in 8,942 gross (3,443 net) productive wells across 1,032,500 gross (484,700 net) developed acres in our five core geographical areas. We believe this geographic mix of properties and organic drilling opportunities, combined with our continuing business strategy of acquiring and exploiting properties in these areas, presents us with multiple opportunities for success in executing our strategy because we are not dependent on any particular producing regions or geological formations. As a result of the Celero acquisitions, we have enhanced the production stability and reserve life of our developed reserves. Additionally, the Celero properties contain identifiable growth opportunities to significantly increase production in the near and intermediate term.

     Experienced Management Team. Our management team averages over 25 years of experience in the oil and natural gas industry. Our personnel have extensive experience in each of our core geographical areas and in all of our operational disciplines. In addition, each of our acquisition professionals has at least 25 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 1,294 square miles of 3-D seismic data, digital well logs and other subsurface information. This data is analyzed with state of the art geophysical and geological computer resources dedicated to the accurate and efficient characterization of the subsurface oil and natural gas reservoirs that comprise our asset base. Computer applications enable us to quickly generate reports and schematics on our wells. In addition, our information systems enable us to update our production databases through daily uploads from hand held computers in the field. This commitment to technology has increased the productivity and efficiency of our field operations development activities.

Proved Reserves

     Our estimated proved reserves as of December 31, 2005 are summarized in the table below.

																		Future
																		Capital
		Oil				Natural Gas				Total				% of Total				Expenditures
		(MMBbl)				(Bcf)				(MMBOE)				Proved				(In thousands)
Permian Basin:
PDP			34.8				46.1				42.5				35	%		$	0.2
PDNP			12.2				5.9				13.2				11	%			66.8
PUD			58.8				32.5				64.2				54	%			431.0
Total Proved			105.8				84.5				119.9				100	%		$	498.0
Rocky Mountains (1):
PDP			34.2				64.3				45.0				77	%		$	1.4
PDNP			1.3				4.7				2.0				4	%			3.1
PUD			5.2				36.5				11.3				19	%			112.9
Total Proved			40.7				105.5				58.3				100	%		$	117.4
Mid-Continent:
PDP			23.2				30.1				28.2				53	%		$	12.9
PDNP			1.7				2.3				2.1				4	%			13.9
PUD			21.7				9.5				23.3				43	%			193.3
Total Proved			46.6				41.9				53.6				100	%		$	220.1
Gulf Coast:
PDP			1.9				46.6				9.7				53	%		$	3.3
PDNP			1.5				8.3				2.9				16	%			3.1
PUD			0.8				28.9				5.6				31	%			45.3
Total Proved			4.2				83.8				18.2				100	%		$	51.7
Michigan:
PDP			0.6				54.7				9.8				71	%		$	0.0
PDNP			0.5				4.4				1.2				9	%			1.0
PUD			0.8				11.6				2.6				20	%			20.9
Total Proved			1.9				70.7				13.6				100	%		$	21.9
Total Company:
PDP			94.7				241.8				135.2				51	%		$	17.8
PDNP			17.2				25.6				21.4				8	%			87.9
PUD			87.3				119.0				107.0				41	%			803.4
Total Proved			199.2				386.4				263.6				100	%		$	909.1

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. During 2005, sales to Teppco Crude Oil LLC accounted for 10% of our total oil and natural gas production revenue. During 2004 and 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. Whiting Oil and Gas Corporation’s credit agreement is also secured by a first lien on substantially all of our assets. We do not believe that any of these burdens materially interfere with the use of our properties in the operation of our business.

     We believe that we have satisfactory title to or rights in all of our producing properties. As is customary in the oil and 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

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

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

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

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

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

Regulation of Transportation of Oil

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

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

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

Regulation of Production

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

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

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

     Superfund. The Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as “CERCLA” or “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the “owner” or “operator” of a disposal site or sites where a release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, such persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our ordinary operations, we may generate material that may fall within CERCLA’s definition of a “hazardous substance.” Consequently, we may be jointly and severally liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these materials have been disposed or released.

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

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

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

     Oil Pollution Act. The Oil Pollution Act of 1990, also known as “OPA,” and regulations issued under OPA impose strict, joint and several liability on “responsible parties” for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permittee of the area in which an offshore facility is located. The OPA establishes a liability limit for onshore facilities of $350 million while the liability limit for offshore facilities is the payment of all removal costs plus up to $75 million in other damages but these limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a cleanup. The OPA also requires the lessee or permittee of the offshore area in which a covered offshore facility is located to establish and maintain evidence of financial responsibility in the amount of $35 million ($10 million if the offshore facility is located landward of the seaward boundary of a state) to cover liabilities related to an oil spill for which such person is statutorily responsible. The amount of financial responsibility required under OPA may be increased up to $150 million, depending on the risk represented by the quantity or quality of oil that is handled by the facility. Any failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to administrative, civil or criminal enforcement actions. We believe we are in compliance with all applicable OPA financial responsibility obligations. Moreover, we are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on us.

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

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

     Historically, the EPA had regulations under the authority of the CWA that required certain oil and natural gas exploration and production projects to obtain permits for construction projects with storm water discharges. However, the EPAct of 2005 nullified most of the EPA regulations that required permitting of oil and natural gas construction projects. There are still some States that regulate the discharge of storm water from oil and natural gas construction projects. Costs may be associated with the treatment of wastewater and/or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. In Section 40 CFR 112 of the regulations, the EPA promulgated

the Spill Prevention, Control, and Countermeasure, or SPCC, regulations, which require certain oil containing facilities to prepare plans and meet construction and operating standards. The SPCC regulations were revised in 2002 and will require the amendment of SPCC plans and the modification of spill control devices at many facilities. The due date for having plans completed and control devices in place was extended on December 12, 2005 with the new compliance date being October 31, 2007. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution and that any amendment and subsequent implementation of our SPCC plans will be performed in a timely manner and not have a significant impact on our operations.

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

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

Employees

     As of December 31, 2005, we had 309 full-time employees, including 24 senior level geoscientists and 27 petroleum engineers. Our employees are not represented by any labor unions. We consider our relations with our employees to be satisfactory, and have never experienced a work stoppage or strike.

Available Information

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

Item 1A.  Risk Factors

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

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

     The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Crude oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

	•		changes in global supply and demand for oil and natural gas;
	•		the actions of the Organization of Petroleum Exporting Countries;
	•		the price and quantity of imports of foreign oil and natural gas;
	•		political and economic conditions, including embargoes, in oil producing countries or affecting other oil-producing activity;
	•		the level of global oil and natural gas exploration and production activity;
	•		the level of global oil and natural gas inventories;
	•		weather conditions;
	•		technological advances affecting energy consumption;
	•		domestic and foreign governmental regulations;
	•		proximity and capacity of oil and natural gas pipelines and other transportation facilities;
	•		the price and availability of competitors’ supplies of oil and natural gas in captive market areas; and
	•		the price and availability of alternative fuels.

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

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

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

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

Our acquisition activities may not be successful.

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

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

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

     Of the reserves that we acquired from Celero in the North Ward Estes field, 62% are proved undeveloped reserves. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. In addition, the development of these reserves will require the use of enhanced recovery techniques, including water flood and CO₂ injection installations, the success of which is less predictable than traditional development techniques. Therefore, ultimate recoveries from these fields may not match current expectations.

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

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

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

     Our business strategy includes a continuing acquisition program. During 2005, we completed four separate acquisitions of producing properties with a combined purchase price of $897.7 million for estimated proved reserves as of the effective dates of the acquisitions of approximately 133.7 MMBOE, representing an average cost of approximately $6.71 per BOE of estimated proved reserves. The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following:

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

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

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

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

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

     As of December 31, 2005, we had $260.0 million in outstanding consolidated indebtedness under Whiting Oil and Gas Corporation’s credit agreement with $527.5 million of available borrowing capacity, as well as $615.1 million of Senior Subordinated Notes outstanding. We are permitted to incur additional indebtedness, provided we meet certain requirements in the indentures governing our senior subordinated notes and Whiting Oil and Gas Corporation’s credit agreement.

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

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

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

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

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

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

	•		pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our subordinated debt;
	•		make loans to others;
	•		make investments;
	•		incur additional indebtedness or issue preferred stock;
	•		create certain liens;
	•		sell assets;
	•		enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
	•		consolidate, merge or transfer all or substantially all of the assets of us and our restrict subsidiaries taken as a whole;
	•		engage in transactions with affiliates;
	•		enter into hedging contracts;
	•		create unrestricted subsidiaries; and
	•		enter into sale and leaseback transactions.

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

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

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

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

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

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

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

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

     The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown or incorporated by reference in this prospectus.

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

     Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown or incorporated by reference in this prospectus. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

     You should not assume that the present value of future net revenues from our proved reserves referred to in this prospectus is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. If natural gas prices decline by $0.10 per Mcf, then the standardized measure of discounted future net cash flows of our estimated proved reserves as of December 31, 2005 would have decreased from $2,882.9 million to $2,867.8 million. If oil prices decline by $1.00 per barrel, then the standardized measure of discounted future net cash flows of our estimated proved reserves as of December 31, 2005 would have decreased from $2,882.9 million to $2,818.1 million.

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

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

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

     We describe some of our current prospects and our plans to explore those prospects in this Annual Report on Form 10-K. A prospect is a property on which we have identified what our geoscientists believe, based on available seismic and geological information, to be indications of oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. The analogies we draw from available data from other wells, more fully explored prospects or producing fields may not be applicable to our drilling prospects.

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

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

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

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

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

     If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure of an operator of our wells to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore

depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells, and use of technology. Because we do not have a majority interest in most wells we do not operate, we may not be in a position to remove the operator in the event of poor performance.

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

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

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

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

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

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

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

     Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.

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

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

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

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

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

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

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

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

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

     We operate in a highly competitive environment for acquiring properties, marketing oil and 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. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

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

     We enter into hedging transactions for our oil and natural gas production to reduce our exposure to fluctuations in the price of oil and natural gas. Our hedging transactions have to date consisted of financially settled crude oil and natural gas forward sales contracts with major financial institutions. As of December 31, 2005, we have contracts maturing in 2006 covering the sale of between 1,500,000 and 1,600,000 MMbtu of natural gas per month and between 410,000 and 450,000 barrels of oil per month. Whiting Oil and Gas Corporation’s credit agreement required us to hedge at least 55% of our total forecasted PDP production from the Postle properties and the North Ward Estes properties for the period through March 31, 2007 for natural gas and December 31, 2008 for oil. These hedges were put in place during the third quarter of 2005. See “Quantitative and Qualitative Disclosure about Market Risk — Commodity Risk” for pricing and a more detailed discussion of our hedging transactions.

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

Item 1B.  Unresolved Staff Comments

None.

Item 2.     Properties

Summary of Oil and Gas Properties and Projects

Permian Basin Region

     Our Permian Basin operations include assets in Texas and New Mexico. As of December 31, 2005, the Permian Basin region contributed 119.9 MMBOE (88% crude oil) of estimated proved reserves to our portfolio of operations, which represented 45% of our total estimated proved reserves. Approximately 95% of the proved reserves of our Permian Basin operations are related to properties in Texas.

     North Ward Estes. The North Ward Estes field includes six base leases with 100% working interest in 58,000 gross and net acres in Ward and Winkler Counties, Texas. As of December 31, 2005, there were approximately 636 producing wells and 667 injection wells. The Yates formation at 2,600 feet is the primary producing zone with additional production from other zones including the Queen at 3,000 feet. As part of this acquisition, we also acquired the rights to deeper horizons under 34,590 gross acres in the North Ward Estes field. The North Ward Estes properties produced at an estimated average net daily rate of 4,930 barrels of oil (including NGLs) and 3,700 Mcf of natural gas during the month of December 2005. In the North Ward Estes field, the estimated proved reserves as of December 31, 2005 were approximately 22% PDP, 16% PDNP and 62% PUD.

     The North Ward Estes field was initially developed in the 1930’s and full scale waterflooding was initiated in 1955. A CO₂ enhanced recovery project was implemented in the core of the field in 1989, but was terminated in 1996 after a successful top lease by a third party. We plan to expand the waterflood operations in the field during 2006 as well as reinitiate a CO₂ project in 2007.

     Included in the North Ward Estes acquisition were interests in certain other fields encompassing approximately 51,200 gross acres (33,000 net). These other fields include approximately 800 oil and natural gas wells within the Permian Basin of Texas and New Mexico. These properties produced at an estimated average net daily rate of 810 barrels of oil (including NGLs) and 1,900 Mcf of natural gas during the month of December 2005.

     Parkway (Delaware) Unit. We own a 61.5% non-operated working interest in the Parkway (Delaware) Unit, a waterflood concentrated on 920 gross acres in Eddy County, New Mexico. Enhancements to the waterflood for 2005 involved continuation of the project to convert existing five-spot patterns to nine-spot patterns with the drilling of nine wells in 2005.

     Would Have Field. We own an approximately 87% operated working interest in the Would Have field in Howard County, Texas, currently producing from 56 wells. Discovered in 2001, this field produces from two sub-units of the Clearfork Formation, the Would Have and the Dillard Limestones. We expect to expand the successful waterflood initiated in the western half of the field in May 2004 to the eastern portion of the field in 2006. Efforts are underway to identify additional locations outside of the main Would Have field reservoir development.

     Keystone South Field. Our 100% working interest in the Keystone field provides a solid production base plus a portfolio of exploitation opportunities. The property covers a surface area of 7,260 acres in Winkler County, Texas. Most current production comes from the Clearfork Formation, with additional production from the Wichita, Wolfcamp, Devonian, Silurian, McKee and Ellenburger. The 2005 drilling program at Keystone South targeted the shallow Clearfork and Wichita-Albany formations with nine wells. Targeted for 2006, development of deeper pay horizons should benefit from a 3-D seismic survey that was conducted in 2005.

Rocky Mountain Region

     Our Rocky Mountain operations include assets in the states of North Dakota, Montana, Colorado, Utah, Wyoming, California and in the Canadian province of Alberta. As of December 31, 2005, our estimated proved reserves in the Rocky Mountain region were 58.3 MMBOE (70% oil), which represented 22% of our total estimated proved reserves. The majority of our reserves in the Rocky Mountain region are in North Dakota and Wyoming. Approximately 43% of the proved reserves of our Rocky Mountain operations are related to assets in North Dakota. Our Canadian assets consist solely of our 50% working interest in the Cessford field located in southern Alberta, with total proved reserves of 0.8 MMBOE.

     Billings Nose Drilling Program. Over the last five years, we have established a high concentration of producing wells and approximately 33,000 acres in the Billings Nose area of Billings County, North Dakota. These assets include the Big Stick Madison Unit and North Elkhorn Ranch Unit along with much of the acreage located between these two fields. During the last two years, we have acquired 99 square miles of 3D seismic data in this area and have since identified multiple opportunities in a variety of reservoirs including the Red River, Duperow, Bakken and Mission Canyon Formations. In the fourth quarter of 2005 we drilled two new natural gas discoveries in the Red River Formation, and a new Bakken horizontal well which had favorable results during drilling operations and is currently being completed. For the remainder of 2006, we expect to drill up to six Mission Canyon wells in the Big Stick and North Elkhorn Ranch fields, up to six Bakken horizontal wells, and three to six Red River wells. In addition to the Billings Nose area, we have acquired approximately 100,000 acres prospective in the Bakken and Red River formations in other parts of North Dakota.

     Nisku A Drilling Program. We made a significant exploration discovery in 2004 in western Billings County, North Dakota in the Nisku A zone. After this exploration success, we ramped up activity in the area and drilled a total of ten wells by the end of 2004. During 2005 we expanded our program by drilling eight casing-exit wells. We also drilled or participated in 13 grass-roots horizontal wells. As a consequence, the play is now well into the development stage with a total of nine remaining wells planned for 2006. We have determined that much of the area we have defined in our drilling program has strong potential for enhanced oil recovery through waterflood and we are formulating plans for potential implementation.

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

     Green River Basin—Siberia Ridge. Siberia Ridge is within the greater Wamsutter Arch area of Sweetwater County, Wyoming and produces from a continuous-phase natural gas accumulation in the Cretaceous Almond Formation at 10,500 feet. Our properties in the Siberia Ridge field resulted from the acquisition of Equity Oil Company in 2004 and were further enhanced by a producing property acquisition in early 2005. In 2004, the spacing rules governing the well density in the Siberia Ridge field were adjusted to allow for up to two wells per 160 acres. This new configuration resulted in a total of 44 additional potential locations on our acreage. Our development program commenced in mid-2005 with the drilling of five new wells. We have implemented a focused effort on the identification, selective perforation and stimulation of the various natural gas productive zones within the Almond Formation in order to optimize production. Completion operations are currently underway with encouraging initial rates. We plan to drill up to nine additional wells in 2006.

     California. As of December 31, 2005, our California operations contributed 1.1 MMBOE (100% natural gas) of net proved reserves to our portfolio of operations, which represented 0.4% of our total estimated proved reserves. Our assets in this region are located in the Sacramento Basin of California, and the Todhunters Lake and Willow Slough fields of Yolo County, California. We also own non-operated working interests in Colusa and Glenn Counties, California.

Mid-Continent Region

     Our Mid-Continent operations include assets in Oklahoma, Arkansas and Kansas. The majority of the proved value within our Mid-Continent operations is related to properties in Postle.

     Postle Field. The Postle field, located in Texas County, Oklahoma, includes five producing units and one producing lease covering a total of approximately 25,600 gross acres (24,223 net) with working interests of 94% to 100%. Three of the units are currently under CO₂ enhanced recovery projects. As of December 31, 2005, there were 91 producing wells and 105 injection wells completed in the Morrow zone at 6,100 feet. The Postle properties produced at an estimated average net daily rate of 4,190 Bopd (including NGLs) and 660 Mcf/d of natural gas during the month of December 2005. In the Postle field, the estimated proved reserves as of December 31, 2005 were 47% PDP, 4% PDNP and 49% PUD.

     The Postle field was initially developed in the early 1960’s and unitized for waterflood in 1967. Enhanced recovery projects using CO₂ were initiated in 1995 and continue in three of the five units. We plan to expand the current CO₂ projects into the rest of the units. These expansion projects include the restoration of shut-in wells and the drilling of new producing and injection wells. This expansion work is underway, with two drilling rigs and six workover rigs currently active in the field.

     In connection with the acquisition of the Postle properties, we acquired 100% ownership of the Dry Trails Gas Plant located in the Postle field. This gas processing plant separates CO₂ gas from the produced wellhead mixture of hydrocarbon and CO₂ gas, so that the CO₂ gas can be reinjected into the producing formation. Plans are underway to increase the plant capacity from its current capacity of 43 MMcf/d to 83 MMcf/d by 2007 to support the expanded CO₂ injection projects.

     We also acquired a 60% interest in the 120 mile TransPetco operated CO₂ transportation pipeline serving the Postle field, thereby assuring the delivery of CO₂ at a fair tariff. A long-term CO₂ purchase agreement was executed in 2005 with a major integrated oil and natural gas company to provide the necessary CO₂ for the expansion planned in the field.

Gulf Coast Region

     Our Gulf Coast operations include assets located in Texas, Louisiana and Mississippi. As of December 31, 2005, the Gulf Coast region contributed 18.2 MMBOE (23% oil) of proved reserves to our portfolio of operations, which represented 7% of our total estimated proved reserves. Approximately 84% of the proved reserves of our Gulf Coast operations are related to properties in Texas.

     Stuart City Reef Trend. In June 2001, we acquired an average 65% working interest in five fields in the Stuart City Reef Trend: Word North, Yoakum, Kawitt, Sweet Home, and Three Rivers. Production in the Stuart City Reef Trend comes primarily from the Edwards, Wilcox, and Sligo formations at depths between 7,000 and 16,000 feet.

     In late 2003 we began a combination development and exploration program targeting multiple sandstone natural gas reservoirs within the Wilcox Formation. We have been active in this area, drilling nine wells in 2005 and are planning an additional six in 2006. In addition, we are currently planning to conduct a 40 square mile 3-D seismic program designed to expand this play into new areas. Relatively low drilling costs, multiple objective natural gas reservoirs and predictable reserves have combined to make this a low risk economic play with significant upside.

     During the third quarter of 2005, we resumed our Edwards horizontal drilling program with two new wells in the Word North field and are currently completing the second of three Edwards wells in the Kawitt field. Initial results from these wells have been in line with our expectations.

Vicksburg Trend. Our holdings in the Vicksburg and Frio Trends are concentrated primarily in the South Midway field (operated by EOG Resources) in San Patricio County, Texas and the Agua Dulce field. During 2005, operations were active in these areas where we drilled or participated in eleven new wells targeting multiple natural gas productive sands in the Vicksburg and Frio Formations at depths between 10,000 and 14,500 feet. Results from this program have encouraged us to drill up to five additional wells in South Midway and up to three wells in Agua Dulce during 2006.

Michigan Region

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

     Antrim Production. In northern Michigan, we own an interest in over 50 multi-well Antrim Shale natural gas projects with proved producing reserves and ongoing development drilling. During 2005, we participated in the drilling and completion of 20 Antrim Shale wells. In 2006, we plan to continue to pursue the development drilling opportunities including the evaluation of horizontal drilling.

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

     During 2005 we drilled two Glenwood / Prarie du Chien (“PdC”) wells in the Clayton field. Both of these wells encountered hydrocarbons in the Middle interval of the PdC which had not previously produced in addition to behind-pipe reserves in the Upper PdC, the primary producing interval. We have been very encouraged by the results. We are in the process of working with a drilling contractor to move another drilling rig into the state of Michigan. Our plans at this point are to use this rig to drill both operated wells and wells operated by others in which we own an interest.

Acreage

     The following table summarizes gross and net developed and undeveloped acreage at December 31, 2005 by state (net acreage is our percentage ownership of gross acreage). Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.

		Developed Acreage								Undeveloped Acreage								Total Acreage
		Gross				Net				Gross				Net				Gross				Net
California			22,822				9,763				3,658				373				26,480				10,136
Colorado			51,956				28,481				30,702				6,204				82,658				34,685
Kansas			850				561				76,751				75,408				77,601				75,969
Louisiana			38,135				10,566				5,338				2,359				43,473				12,925
Michigan			187,756				68,310				7,360				5,852				195,116				74,162
Montana			46,524				12,249				78,606				46,753				125,130				59,002
North Dakota			141,774				76,593				283,629				153,934				425,403				230,527
Oklahoma			63,948				49,426				451				90				64,399				49,516
Texas			328,849				153,596				42,151				30,388				371,000				183,984
Utah			21,156				11,359				36,003				16,206				57,159				27,565
Wyoming			110,776				56,958				49,733				16,166				160,509				73,124
Other*			17,945				6,815				1,081				456				17,087				7,271
Total			1,032,491				484,677				615,463				354,189				1,646,015				838,866

Production History

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

		Year Ended December 31,
		2005				2004				2003
Oil production (MMbbls)			7.0				3.7				2.6
Natural gas production (Bcf)			30.3				25.1				21.6
Total production (MMBOE)			12.1				7.9				6.2
Daily production (MBOE/d)			33.1				21.6				17.0
Average sales prices:
Natural gas (per Mcf)		$	7.03			$	5.56			$	4.78
Effect of natural gas hedges on average price (per Mcf)		$	(0.47	)		$	—			$	(0.30	)
Natural gas net of hedging (per Mcf)		$	6.56			$	5.56			$	4.48
Oil (per Bbl)		$	51.26			$	38.72			$	27.50
Effect of oil hedges on average price (per Bbl)		$	(2.72	)		$	(1.33	)		$	(0.37	)
Oil net of hedging (per Bbl)		$	48.54			$	37.39			$	27.13
Per BOE data:
Sales price (net of hedging)		$	44.70			$	35.23			$	27.00
Lease operating expenses		$	9.24			$	6.90			$	6.96
Production taxes		$	2.99			$	2.16			$	1.74
Depreciation, depletion and amortization expenses		$	8.08			$	6.90			$	6.66
General and administrative expenses		$	2.53			$	2.45			$	2.10

Productive Wells

     The following table presents our ownership at December 31, 2005 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(1)
		Gross				Net				Gross				Net				Gross				Net
Permian Basin			3,513				1,511				194				129				3,707				1,640
Rocky Mountains			2,026				476				421				170				2,447				646
Mid-Continent			504				298				204				84				708				382
Gulf Coast			135				56				835				266				970				322
Michigan			77				58				1,033				395				1,110				453
Total			6,255				2,399				2,687				1,044				8,942				3,443

Drilling Activity

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

		Gross Wells												Net Wells
		Productive				Dry				Total				Productive				Dry				Total
2005:
Development			276				18				294				164.7				10.6				175.3
Exploratory			7				7				14				1.3				3.9				5.2
Total			283				25				308				166.0				14.5				180.5
2004:
Development			157				7				164				73.4				3.7				77.1
Exploratory			3				2				5				1.5				0.2				1.7
Total			160				9				169				74.9				3.9				78.8
2003:
Development			64				5				69				20.9				2.3				23.2
Exploratory			—				3				3				—				1.6				1.6
Total			64				8				72				20.9				3.9				24.8

Item 3.     Legal Proceedings

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

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

     No matters were submitted to a vote of security holders during the fourth quarter of 2005.

EXECUTIVE OFFICERS OF THE REGISTRANT

     The following table sets forth certain information, as of February 15, 2006, regarding the executive officers of Whiting Petroleum Corporation:

Name		Age				Position
James J. Volker			59			Chairman, President and Chief Executive Officer
D. Sherwin Artus			68			Senior Vice President
James T. Brown			53			Vice President, Operations
Bruce R. DeBoer			53			Vice President, General Counsel and Corporate Secretary
J. Douglas Lang			56			Vice President, Reservoir Engineering/Acquisitions
Patricia J. Miller			68			Vice President, Human Resources
David M. Seery			51			Vice President, Land
Michael J. Stevens			40			Vice President and Chief Financial Officer
Mark R. Williams			49			Vice President, Exploration and Development
Brent P. Jensen			36			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 over forty years. Mr. Artus holds a Bachelor’s Degree in geologic engineering and a Master’s Degree in mining engineering from the South Dakota School of Mines and Technology.

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

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

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

     Patricia J. Miller joined us in April 1980 as Corporate Secretary and as Secretary to our President, becoming Director of Human Resources in May 1994. In November 2001, she was appointed Vice President of Human Resources. She served as Corporate Secretary until January 2005. Mrs. Miller attended business school at Otero Junior College in LaJunta, Colorado and at Texas A & I in Kingsville, Texas.

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

     Michael J. Stevens joined us in May 2001 as Controller, and became Treasurer in January 2002 and became Vice President and Chief Financial Officer in March 2005. From 1993 until May 2001, he served as Chief Financial Officer, Controller, Secretary and Treasurer at Inland Resources Inc., a company engaged in oil and 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.

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

     Brent P. Jensen joined us in August 2005 as Controller, and he became Treasurer in January 2006. He was previously a Senior Manager with PricewaterhouseCoopers L.L.P. in Houston, Texas, where he held various positions in their oil and gas audit practice since joining that firm in 1994, including a four year assignment in their Moscow, Russia office and almost three years in their Milan, Italy office. He has 12 years of oil and gas accounting experience and is a Certified Public Accountant. Mr. Jensen holds a Bachelor of Arts degree with an emphasis on accounting and business from the University of California, Los Angeles.

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

PART II

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

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

		High				Low
Fiscal Year Ended December 31, 2005
Fourth Quarter (Ended December 31, 2005)		$	44.91			$	36.77
Third Quarter (Ended September 30, 2005)		$	46.17			$	36.39
Second Quarter (Ended June 30, 2005)		$	43.20			$	28.19
First Quarter (Ended March 31, 2005)		$	46.30			$	27.76
Fiscal Year Ended December 31, 2004
Fourth Quarter (Ended December 31, 2004)		$	34.22			$	27.52
Third Quarter (Ended September 30, 2004)		$	31.20			$	21.85
Second Quarter (Ended June 30, 2004)		$	27.59			$	21.50
First Quarter (Ended March 31, 2004)		$	23.94			$	18.45

     On February 15, 2006, there were 921 holders of record of our common stock.

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

Item 6.     Selected Financial Data

     The consolidated income statement information for the years ended December 31, 2005, 2004 and 2003 and the balance sheet information at December 31, 2005 and 2004 are derived from our audited financial statements included elsewhere in this report. The consolidated income statement information for the years ended December 31, 2002 and 2001 and the balance sheet information at December 31, 2003, 2002 and 2001 are derived from audited financial statements that are not included in this report. Our historical results include the results from our recent acquisitions beginning on the following dates: Green River Basin, March 31, 2005; Limited Partnership Interests, June 23, 2005; Postle Properties, August 4, 2005; and North Ward Estes and Ancillary Properties, October 4, 2005.

		Year Ended December 31,
		2005				2004				2003				2002				2001
						(dollars in millions except per share data)
Consolidated Income Statement Information:
Revenues and other income:
Oil and gas sales		$	573.2			$	281.1			$	175.7			$	122.7			$	125.2
Gain (loss) on oil and gas hedging activities			(33.4	)			(4.9	)			(8.7	)			(3.2	)			2.3
Gain on sale of oil and gas properties			—				1.0				—				1.0				11.7
Gain on sale of marketable securities			—				4.8				—				—				—
Interest income and other			0.6				0.1				0.3				—				0.2
Total revenues and other income		$	540.4			$	282.1			$	167.3			$	120.5			$	139.4
Costs and expenses:
Lease operating		$	111.6			$	54.2			$	43.2			$	32.9			$	29.8
Production taxes			36.1				16.8				10.7				7.4				6.5
Depreciation, depletion and amortization (1)			97.6				54.0				41.2				43.6				26.9
Exploration and impairment			16.7				6.3				3.2				1.8				0.8
General and administrative			30.6				19.2				13.0				10.3				9.4
Change in Production Participation Plan liability			9.7				1.7				(0.2	)			1.7				1.5
Phantom equity plan (2)			—				—				10.9				—				—
Interest expense			42.0				15.9				9.2				10.9				10.2
Total costs and expenses		$	344.3			$	168.1			$	131.2			$	108.6			$	85.1
Income before income taxes and cumulative change in accounting principle		$	196.1			$	114.0			$	36.1			$	11.9			$	54.3
Income tax expense (3)			74.2				44.0				13.9				4.2				13.1
Income before cumulative change in accounting principle			121.9				70.0				22.2				7.7				41.2
Cumulative change in accounting principle (4)			—				—				3.9				—				—
Net income		$	121.9			$	70.0			$	18.3			$	7.7			$	41.2
Income per common share before cumulative change in accounting principle, basic		$	3.89			$	3.38			$	1.18			$	0.41			$	2.20
Income per common share before cumulative change in accounting principle, diluted		$	3.88			$	3.38			$	1.18			$	0.41			$	2.20
Net income per common share, basic		$	3.89			$	3.38			$	0.98			$	0.41			$	2.20
Net income per common share, diluted		$	3.88			$	3.38			$	0.98			$	0.41			$	2.20
Other Financial Information:
Net cash provided by operating activities		$	330.4			$	134.1			$	91.9			$	62.6			$	62.3
Net cash used in investing activities		$	1,126.9			$	524.4			$	47.6			$	157.5			$	86.5
Net cash provided by financing activities		$	805.2			$	338.4			$	4.4			$	98.7			$	23.9
Ratio of earnings to fixed charges (5)			5.64	x			8.01	x			4.85	x			2.08	x			6.10	x
Capital expenditures		$	1,126.9			$	530.6			$	47.6			$	165.4			$	99.6

		As of December 31,
		2005				2004				2003				2002				2001
						(dollars in millions)
Balance Sheet Information:
Total assets		$	2,235.2			$	1,092.2			$	536.3			$	448.5			$	319.8
Total debt		$	875.1			$	328.4			$	188.0			$	265.5			$	163.6
Stockholders’ equity		$	997.9			$	612.4			$	259.6			$	122.8			$	111.5

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

Forward Looking Statements

     This report contains statements that we believe to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than historical facts, including, without limitation, statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and debt levels, and plans and objectives of management for future operations, are forward-looking statements. When used in this report, words such as we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. Some, but not all, of the risks and uncertainties include: declines in oil or natural gas prices; our level of success in exploitation, exploration, development and production activities; the timing of our exploration and development expenditures, including our ability to obtain drilling rigs; our ability to obtain external capital to finance acquisitions; our ability to identify and complete acquisitions and to successfully integrate acquired businesses, including our ability to realize cost savings from completed acquisitions; unforeseen underperformance or liabilities associated with acquired properties; inaccuracies of our reserve estimates or our assumptions underlying them; failure of our properties to yield oil or natural gas in commercially viable quantities; uninsured or underinsured losses resulting from our oil and natural gas operations; our inability to access oil and natural gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and natural gas operations; risks related to our level of indebtedness and periodic redeterminations of our borrowing base under our credit agreement; our ability to replace our oil and natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and natural gas industry; risks arising out of our hedging transactions and other risks described under the caption “Risk Factors.” We assume no obligation, and disclaim any duty, to update the forward-looking statements in this report.

Overview

     We are engaged in oil and natural gas exploitation, acquisition, exploration and production activities primarily in the Permian Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the United States. Over the last five 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 that have complemented our existing operations. We intend to continue to acquire both operated and non-operated interests to the extent we believe they meet our return criteria. In addition, our willingness to acquire non-operated properties in new geographic regions provides us with geophysical and geologic data in some cases that leads to further acquisitions in the same region, whether on an operated or non-operated basis. We sell properties when we are of the opinion that the sale price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own.

     Our revenue, profitability and future growth rate depend on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and 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.

2005 Acquisitions

     We completed four separate acquisitions of producing properties during 2005. The combined purchase price for these four acquisitions was $897.7 million for total estimated proved reserves as of the effective dates of the acquisitions of approximately 133.7 MMBOE. Because of our substantial recent acquisition activity, our discussion and analysis of our historical financial condition and results of operations for the periods discussed below may not necessarily be comparable with or applicable to our future results of operations. Our historical results include the results from our recent acquisitions beginning on the following dates: North Ward Estes and Ancillary Properties, October 4, 2005; Postle Properties, August 4, 2005; Limited Partnership Interests, June 23, 2005; and Green River Basin, March 31, 2005.

North Ward Estes and Ancillary Properties

     On October 4, 2005, we acquired the operated interest in the North Ward Estes field in Ward and Winkler counties, Texas, and certain smaller fields located in the Permian Basin from Celero. The purchase price was $459.2 million, consisting of $442.0 million in cash and 441,500 shares of our common stock, for estimated proved reserves of approximately 82.1 MMBOE as of the acquisition effective date of July 1, 2005, resulting in a cost of approximately $5.58 per BOE of estimated proved reserves. The average daily production from the properties was approximately 4.6 MBOE/d as of the acquisition effective date. We funded the cash portion of the purchase price with the net proceeds from our public offering of common stock and private placement of 7% Senior Subordinated Notes due 2014, both of which closed on October 4, 2005. See below for estimated future development costs.

Postle Properties

     On August 4, 2005, we acquired the operated interest in producing oil and natural gas fields located in the Oklahoma Panhandle. The purchase price was $343.0 million for estimated proved reserves of approximately 40.3 MMBOE as of the acquisition effective date of July 1, 2005, resulting in a cost of approximately $8.52 per BOE of estimated proved reserves. The average daily production from the properties was approximately 4.2 MBOE/d as of the acquisition effective date. We funded the acquisition through borrowings under the credit agreement of Whiting Oil and Gas Corporation, our wholly owned subsidiary. See below for estimated future development costs.

     The following table presents estimated future development costs for the North Ward Estes and Ancillary Properties and Postle Properties as of December 31, 2005 (in thousands):

		North Ward Estes
		and Ancillary
		Properties				Postle Properties				Total
PDP		$	—			$	12,906			$	12,906
PDNP			64,782				12,266				77,048
PUD			361,688				186,481				548,169
Total		$	426,470			$	211,653			$	638,123

Limited Partnership Interests

On June 23, 2005, we completed our acquisition of all of the limited partnership interests in three institutional partnerships managed by our wholly-owned subsidiary Whiting Programs, Inc. The purchase price was $30.5 million for estimated proved reserves of approximately 2.9 MMBOE as of the acquisition effective date, resulting in a cost of $10.52 per BOE of estimated proved reserves. The partnership properties are located in Louisiana, Texas, Arkansas, Oklahoma and Wyoming. The average daily production from the properties was 0.7 MBOE/d as of the effective date of the acquisition. We funded the acquisition using cash on hand.

Green River Basin

     Green River Basin. On March 31, 2005, we completed our acquisition of operated interests in five producing natural gas fields in the Green River Basin of Wyoming. The purchase price was $65.0 million for estimated proved reserves of approximately 8.4 MMBOE as of the acquisition effective date, resulting in a cost of $7.74 per BOE of

estimated proved reserves. We operate approximately 95% of the average daily production from the properties, which was 1.1 MBOE/d as of the effective date of the acquisition. We funded the acquisition through borrowings under Whiting Oil and Gas Corporation’s credit agreement.

Results of Operations

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

		Year Ended December 31,
		2005				2004				2003
Net production:
Natural gas (Bcf)			30.3				25.1				21.6
Oil (MMbbls)			7.0				3.7				2.6
Net sales (in millions):
Natural gas(1)		$	212.8			$	139.4			$	104.4
Oil(1)		$	360.4			$	141.7			$	71.3
Average sales prices:
Natural gas (per Mcf)		$	7.03			$	5.56			$	4.78
Effect of natural gas hedges on average price (per Mcf)		$	(0.47	)		$	—			$	(0.30	)
Natural gas net of hedging (per Mcf)		$	6.56			$	5.56			$	4.48
Oil (per Bbl)		$	51.26			$	38.72			$	27.50
Effect of oil hedges on average price (per Bbl)		$	(2.72	)		$	(1.33	)		$	(0.37	)
Oil net of hedging (per Bbl)		$	48.54			$	37.39			$	27.13
Cost and expense (per MBOE):
Lease operating expenses		$	9.24			$	6.90			$	6.96
Production taxes		$	2.99			$	2.16			$	1.74
Depreciation, depletion and amortization expense		$	8.08			$	6.90			$	6.66
General and administrative expenses		$	2.53			$	2.45			$	2.10

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

     Oil and Gas Sales. Our oil and gas sales revenue increased $292.2 million to $573.2 million in 2005. Sales are a function of sales volumes and average sales prices. Our sales volumes increased 54% between periods on a BOE basis. The volume increase resulted primarily from acquisition activities and successful drilling activities over the past year that produced new sales volumes that more than offset natural field production decline. Our production volumes for 2005 were slightly less than anticipated due in part to delays in rig availability that caused delays in our development drilling program and temporary pipeline shut downs and workover activity in the first quarter of 2005. Hurricanes Katrina and Rita caused only minor reductions to our 2005 sales volumes, in that only 16,700 BOE of total estimated production was lost during 2005 due to the hurricanes. Our average price for natural gas sales increased 26% and our average price for crude oil increased 32% between periods.

     Loss on Oil and Gas Hedging Activities. We hedged 60% of our natural gas volumes during 2005 incurring a hedging loss of $14.3 million and 32% of our natural gas volumes during 2004 incurring no hedging loss or gain. We hedged 58% of our oil volumes during 2005 incurring a hedging loss of $19.1 million, and 50% of our oil volumes during 2004 incurring a hedging loss of $4.9 million. See Item 7A, “Qualitative and Quantitative Disclosures About Market Risk” for a list of our outstanding oil and natural gas hedges as of February 15, 2006.

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

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

     Lease Operating Expenses. Our lease operating expense increased $57.3 million to $111.6 million in 2005 compared to 2004. The increase resulted primarily from costs associated with new property acquisitions over the past year. Our lease operating expense as a percentage of oil and natural gas sales increased slightly from 19% during 2004 to 20% during 2005. Our lease operating expenses per BOE increased from $6.90 during 2004 to $9.24 during 2005. The increase of 34% was mainly caused by higher costs for electric power and increases in the cost of oil field goods and services due to higher demand in the industry. In addition, our lease operating expenses increased on a BOE basis due to the newly acquired Postle and North Ward Estes properties, which had fourth quarter combined operating costs of $12.72 per BOE relating to the secondary and tertiary recovery projects underway on those fields.

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

     Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) increased $43.6 million to $97.6 million during 2005 as compared to $54.0 million for 2004. The increase resulted from increased production due to our recent acquisitions and an increase in our DD&A rate. On a BOE basis, the rate increased from $6.90 during 2004 to $8.08 in 2005. The primary factors causing the DD&A rate increase were the higher costs of adding proved developed reserves in 2005, the increase in drilling expenditures including the development of proved undeveloped reserves, the costs of which are not considered for DD&A purposes until incurred, and downward net reserve revisions. Changes to the pricing environment can also positively impact our DD&A rate. Price increases allow for longer economic production lives and corresponding increased reserve volumes and, as a result, lower depletion rates. Price decreases have the opposite effect. The components of our DD&A expense were as follows (in thousands):

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

     Exploration and Impairment. Our exploration and impairment costs increased $10.4 million to $16.7 million in 2005 compared to 2004.

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

     Higher exploratory costs resulted from seven exploratory dry holes drilled during 2005 totaling $4.0 million, as compared to two exploratory dry holes in 2004 totaling $0.6 million. We also hired additional geological and geophysical personnel to support the increased drilling budget from $79.4 million in 2004 to $223.6 million in 2005. The impairment charge in 2005 relates primarily to unrecoverable costs associated with our investment in the Cherokee Basin of Kansas. The impairment charge in 2004 was for the write down of cost associated with the High Island field located off the coast of Texas.

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

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

     General and administrative expenses before reimbursements increased $16.6 million to $42.6 million during 2005 compared to $26.0 million during 2004. The largest components of the increase related to higher costs for personnel salaries, benefits and related taxes of $9.2 million, an increase in the current year cash payment under our Production Participation Plan of $3.3 million and the amortization of restricted stock compensation of $2.9 million. Personnel salary expenses were higher in 2005 due primarily to an increase in our employee base resulting from our continued growth. The increased cost of the Production Participation Plan was caused primarily by higher 2005 production volumes and higher average sales prices between years. Restricted stock compensation increased due to the additional issuance of restricted stock in 2005 and due to the layering impact of a multiple year vesting schedule. The increase in reimbursements in 2005 was caused by a higher number of operated properties due to acquisitions and drilling activities during the last half of 2004 and 2005. Our net general and administrative expenses on a BOE basis increased 3% between periods from $2.45 to $2.53. As a percentage of oil and natural gas sales, our general and administrative expenses decreased from 6.8% during 2004 to 5.3% during 2005, as general and administrative costs increased at a slower rate than oil and natural gas sales prices.

     Change in Production Participation Plan Liability. For the year ended December 31, 2005, this non-cash expense increased $8.0 million to $9.7 million from $1.7 million during 2004. This expense represents the change in the vested present value of estimated future payments to be made to participants after 2006 under its Production Participation Plan. Although payments take place over the life of oil and natural gas properties contributed to the Plan, some properties for over 20 years, we must expense the present value of estimated future payments over the Plan’s five year vesting period. During the fourth quarter of 2005, we determined that the expense related to the long-term portion of the Production Participation Plan liability should be presented separately from general and administrative and exploration expenses because of its significance and because the long-term portion of this liability is calculated based on estimated net cash flows to be realized from the future production of oil and natural gas and as such is not currently payable, unlike other general and administrative or exploration expenses. As a result of this reclassification, general and administrative expense and exploration expenses exclude changes in the long-term portion of the Production Participation Plan liability and include only those amounts paid or accrued under the Production Participation Plan that relate to current period oil and natural gas operations. The increase in expense primarily reflects changes to future cash flows estimates due to the effect of a sustained higher price environment and acquisitions during 2005. Assumptions that are used to calculate this liability are subject to estimation and will vary from year to year based on the current market for oil and natural gas prices, discount rates and overall market conditions.

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

		Year Ended December 31,
		2005				2004
Credit Agreement		$	9,997			$	5,893
7.25% Senior Subordinated Notes due 2012			9,758				5,957
7.25% Senior Subordinated Notes due 2013			11,165				—
7% Senior Subordinated Notes due 2014			4,186				—
Alliant Energy			138				150
Amortization of debt issue costs and debt discount			4,076				1,666
Capitalized interest			—				(200	)
Accretion of tax sharing liability			2,725				2,390
Total interest expense		$	42,045			$	15,856

     The increase in interest expense was mainly due to the May 2004 issuance of $150.0 million of 7.25% Senior Subordinated Notes due 2012, the April 2005 issuance of $220.0 million of 7.25% Senior Subordinated Notes due 2013, the October 2005 issuance of $250.0 million of 7% Senior Subordinated Notes due 2014, and additional borrowings outstanding under our amended and restated credit agreement. The additional amortization of debt issue costs and debt discount in 2005 was due to the greater number of days that each instrument was outstanding versus the

prior year. In August of 2004, $75.0 million of the face amount of the 7.25% Senior Subordinated Notes due 2012 notes were swapped to a floating rate. At November 1, 2005, the floating rate component was set at 6.8% through May 1, 2006.

     Our weighted average debt outstanding during 2005 was $553.0 million versus $257.8 million during 2004. Our weighted average effective cash interest rate was 6.4% during 2005 versus 4.7% 2004. After inclusion of non-cash interest costs related to the amortization of debt issue costs and debt discount and the accretion of the tax sharing liability, our weighted average effective all-in interest rate was 7.2% during 2005 versus 5.5% during 2004.

     Income Tax Expense. Income tax expense totaled $74.2 million for 2005 and $44.0 million for 2004, resulting in effective income tax rates of 37.8% and 38.6%, respectively. We were able to defer the majority of our cash income tax obligations due to the level of our drilling expenditures in each year. We reported current income tax expense of $8.5 million in 2005 or 11.5% of the tax provision, as compared to $3.9 million or 8.8% of the tax provision in 2004. The lower rate of current income tax expense in 2004 was mainly due to the use of our 2003 net operating loss carryforward in 2004.

     Net Income. Net income increased from $70.0 million during 2004 to $121.9 million during 2005. The primary reasons for this increase included 27% higher crude oil and natural gas prices net of hedging between periods and a 54% increase in equivalent volumes sold, which were partially offset by higher lease operating expenses, production taxes, DD&A, exploration and impairment, general and administrative, Production Participation Plan and interest expenses in 2005 resulting from our continued growth.

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

     Oil and Gas Sales. Our oil and natural gas sales revenue increased $105.3 million to $281.1 million in 2004. Our sales volumes increased 27% between periods on a BOE basis. The volume increase resulted from successful drilling and acquisition activities over the past year that produced new sales volumes that more than offset natural field decline. Our average price for natural gas sales increased 16% and our average price for crude oil increased 41% between periods.

     Loss on Oil and Gas Hedging Activities. We hedged 32% of our natural gas volumes during 2004 incurring no hedging gains or losses, and 41% of our natural gas volumes during 2003 incurring a hedging loss of $7.7 million. We hedged 50% of our oil volumes during 2004 incurring a hedging loss of $4.9 million, and 8% of our oil volumes during 2003 incurring a loss of $1.0 million.

     Gain on Sale of Marketable Securities. During 2004, we sold all of our holdings in Delta Petroleum, Inc., which trades publicly under the symbol “DPTR”. We realized gross proceeds of $5.4 million and recognized a gain on sale of $4.8 million. At December 31, 2004, we had no investments in marketable securities.

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

     Lease Operating Expenses. Our lease operating expenses per BOE decreased from $6.96 during 2003 to $6.90 during 2004. The decrease was less than 1%, which represented improved operating efficiency more than offsetting price inflation caused by increased demand for goods and services in the industry. Our fourth quarter 2004 lease operating expense per BOE was $6.91, indicating that the seven acquisitions we completed during the third and fourth quarters of 2004 did not significantly affect our rate.

     Production Taxes. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenue before the effects of hedging. We take full advantage of all credits and exemptions allowed in the various taxing jurisdictions. Our production taxes for 2004 and 2003 were 6.0% and 6.1% of oil and natural gas sales, respectively.

     Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) increased from $12.8 million to $54.0 million in 2004. The increase resulted from higher production volumes and an increase in the DD&A rate, as well as the effects of our recent acquisitions. On a BOE basis, the rate increased from $6.66 during 2003 to $6.90 in 2004. The increase in rate is primarily due to 2004 property acquisitions, which we purchased at an average cost of $7.38 per BOE, which was higher than our historical rate. Changes to the pricing

environment can also impact our DD&A rate. Price increases allow for longer economic production lives and corresponding increased reserve volumes and, as a result, lower depletion rates. Price decreases have the opposite effect. The components of our DD&A expense were as follows (in thousands):

		Year Ended
		December 31,
		2004				2003
Depletion		$	51,424			$	38,939
Depreciation			832				835
Accretion of asset retirement obligations			1,754				1,482
Total		$	54,010			$	41,256

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

		Year Ended
		December 31,
		2004				2003
Exploration		$	4,177			$	3,186
Impairment			2,152				—
Total		$	6,329			$	3,186

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

		Year Ended
		December 31,
		2004				2003
General and administrative expenses		$	26,012			$	18,621
Reimbursements			(6,768	)			(5,631	)
General and administrative expenses, net		$	19,244			$	12,990

     General and administrative expenses before reimbursements increased $7.4 million to $26.0 million during 2004. The largest components of the increase related to higher costs for personnel salaries, benefits and related taxes of $2.7 million, an increase in the current year cash payment related to our Production Participation Plan of $2.7 million and an increase in the amortization of restricted stock compensation of $0.6 million. Personnel salary expenses were higher in 2004 due primarily to an increase in our employee base due to our continued growth. The increased cost of the Production Participation Plan was caused primarily by higher production volumes and higher oil and natural gas sales prices between years. We recognized restricted stock compensation expense in 2004 but not in 2003, since this was the first year that we issued restricted stock and incurred an amortization charge. On a BOE basis, the increase between years was from $2.10 to $2.45. The increase in reimbursements was caused by a higher number of operated properties due to 2004 property acquisitions and was also caused by an increase in development drilling.

     Change in Production Participation Plan Liability. For the year ended December 31, 2004, this non-cash expense increased $1.9 million. This expense represents the change in the vested present value of estimated future payments to be made to participants after 2005 under its Production Participation Plan. Although payments take place over the life of oil and natural gas properties contributed to the Plan, some properties for over 20 years, we must expense the present value of estimated future payments over the Plan’s five year vesting period. During the fourth quarter of 2005, we determined that the expense related to the long-term portion of the Production Participation Plan liability should be presented separately from general and administrative and exploration expenses because of its significance and because the long-term portion of this liability is calculated based on estimated net cash flows to be realized from the future production of oil and natural gas and as such is not currently payable, unlike other general and

administrative or exploration expenses. As a result of the reclassification, general and administrative expense and exploration expenses exclude changes in the long-term portion of the Production Participation Plan liability and include only those amounts paid or accrued under the Production Participation Plan that relate to current period oil and natural gas operations. The increase in expense primarily reflects changes to future cash flows estimates due a higher price environment and acquisitions during 2004. Assumptions that are used to calculate this liability are subject to estimation and will vary from year to year based on the current market for oil and natural gas prices, discount rates and overall market conditions.

     Interest Expense. The components of our interest expense were as follows:

		Year Ended
		December 31,
		2004				2003
7.25% Senior Subordinated Notes due 2012		$	5,957			$	—
Credit Agreement			5,893				6,643
Alliant Energy Corporation			150				1,224
Accretion of tax sharing liability			2,390				220
Amortization of debt issue costs and debt discount			1,666				1,090
Capitalized interest			(200	)			—
Total interest expense		$	15,856			$	9,177