10-K 1 form10-k.htm WHITING PETROLEUM CORP. 12-31-07 FORM 10-K form10-k.htm
 




UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
 
FORM 10-K
 

 
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2007
 
or
 
[  ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from _______________ to _______________
 
Commission file number:  001-31899
 
 
Whiting Petroleum Corporation
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction
of incorporation or organization)
 
20-0098515
(I.R.S. Employer
Identification No.)
 
1700 Broadway, Suite 2300
Denver, Colorado
(Address of principal executive offices)
 
 
80290-2300
(Zip code)
 
Registrant’s telephone number, including area code:  (303) 837-1661
 
Securities registered pursuant to Section 12(b) of the Act:
 
Common Stock, $0.001 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.YesTNo£
 
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£NoT
 
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.YesTNo£
 
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.£
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one):
 
Large accelerated filerT
Accelerated filer    £
Non-accelerated filer£
Smaller reporting company   £
 
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes£NoT
 
Aggregate market value of the voting common stock held by non-affiliates of the registrant at June 30, 2007:  $1,494,294,777.
 
Number of shares of the registrant’s common stock outstanding at February 15, 2008:  42,241,356 shares.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the Proxy Statement for the 2008 Annual Meeting of Stockholders are incorporated by reference into Part III.

 
 

 

 
TABLE OF CONTENTS
 
     
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Signatures  
  Exhibit Index  
  EX-10.6 (Production Participation Plan, Amended and Restated February 4, 2008)  
  EX-10.10 (Amended and Restated Production Participation Plan Supplemental Payment Agreement, dated January 14, 2008)  
  EX-12.1 (Computation of Ratio of Earnings to Fixed Charges)  
  EX-21 (Subsidiaries of Whiting Petroleum Corporation)  
  EX-23.1 (Consent of Deloitte & Touche LLP)  
  EX-23.2 (Consent of Cawley, Gillespie & Associates, Inc.)  
  EX-31.1 (Certification by Chairman, President and CEO Pursuant to Section 302)  
  EX-31.2 (Certification by Vice President and CFO Pursuant to Section 302)  
  EX-32.1 (Certification of the Chairman, President and CEO Pursuant to Section 1350)  
  EX-32.2 (Certification of the Vice President and CFO Pursuant to Section 1350)  


CERTAIN DEFINITIONS

Unless the context otherwise requires, the terms “we,” “us,” “our” or “ours” when used in this Annual Report on Form 10-K refer to Whiting Petroleum Corporation, together with its consolidated operating subsidiaries.  When the context requires, we refer to these entities separately.
 
We have included below the definitions for certain 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.
 
“CO2 flood” A tertiary recovery method in which CO2 is injected into a reservoir to enhance oil recovery.
 
completion” The installation of permanent equipment for the production of crude oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
 
“GAAP” Generally accepted accounting principles in the United States of America.
 
“farmout” An assignment of an interest in a drilling location and related acreage conditioned upon the drilling of a well on that location.
 
“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 MMcf 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 Securities and Exchange Commission (“SEC”) guidelines, net of estimated lease operating expense, production taxes and future development costs, using price and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, depreciation, depletion and amortization, or Federal income taxes and discounted using an annual discount rate of 10%. Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC.  See footnote (1) to the Proved Reserves table in Item 1. “Business” for more information.
 
reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
 
working interest” The interest in an crude oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to share in production, subject to all royalties, overriding royalties and other burdens and to share in all costs of exploration, development, operations and all risks in connection therewith.
 
 
 
PART I
 
Item 1.
Business
 
Overview
 
We are an independent oil and gas company engaged in acquisition, development, exploitation, production and exploration activities primarily in the Permian Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the United States.  We were incorporated in 2003 in connection with our initial public offering.
 
Since our inception in 1980, we have built a strong asset base and achieved steady growth through property acquisitions, development and exploration activities.  As of December 31, 2007, our estimated proved reserves totaled 250.8 MMBOE, representing a 1% increase in our proved reserves since December 31, 2006.  Our estimated December 2007 average daily production was 40.3 MBOE/d and implies an average reserve life of approximately 17.1 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, 2007, and our December 2007 average daily production:
 
   
Proved Reserves
       
Core Area
 
Oil (MMbbl)
   
Natural Gas (Bcf)
   
Total (MMBOE)
   
% Oil
   
Pre-Tax PV10% Value(1)
   
December 2007 Average Daily Production (MBOE/d)
 
                           
(In millions)
       
Permian Basin
    100.7       76.0       113.4       89 %   $ 2,483.0       10.7  
Rocky Mountains
    42.2       116.9       61.7       68 %     1,418.0       14.8  
Mid-Continent
    46.0       30.6       51.1       90 %     1,418.0       7.2  
Gulf Coast
    3.5       52.5       12.3       29 %     284.7       4.1  
Michigan
    3.9       50.7       12.3       32 %     254.6       3.5  
Total
    196.3       326.7       250.8       78 %   $ 5,858.3       40.3  
Discounted Future Income Taxes
    -       -       -       -       (1,846.6 )     -  
Standardized Measure of Discounted Future Net Cash Flows
    -       -       -       -     $ 4,011.7       -  
_____________________
 (1)
Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure.  Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes.  We believe pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our oil and natural gas properties.  We further believe investors may utilize our pre-tax PV10% as a basis for comparison of the relative size and value of our reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid.  Our management uses this measure when assessing the potential return on investment related to our oil and gas properties and acquisitions.  However, pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows.  Our pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.
 
While historically we have grown through acquisitions, we are increasingly focused on a balanced exploration and development program while continuing to selectively pursue acquisitions that complement our existing core properties.  We believe that our significant drilling inventory, combined with our operating experience and cost structure, provides us with meaningful organic growth opportunities.
 
 
Our growth plan is centered on the following activities:
 
 
pursuing the development of projects that we believe will generate attractive rates of return;
 
maintaining a balanced portfolio of lower risk, long-lived oil and gas properties that provide stable cash flows;
 
seeking property acquisitions that complement our core areas; and
 
allocating an increasing percentage of our capital budget to leasing and testing new areas.

During 2007, we incurred $578.2 million in acquisition, development and exploration activities, including $529.3 million for the drilling of 277 gross (138.6 net) wells.  Of these new wells, 271 resulted in productive completions and 6 were unsuccessful, yielding a 98% success rate.  We have budgeted $640.0 million for exploration and development drilling expenditures in 2008.
 
Acquisitions and Divestitures
 
The following is a summary of our acquisitions and divestitures during the last two years.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information on these acquisitions and divestitures.
 
2007 Acquisitions.  There were no significant acquisitions during the year ended December 31, 2007.
 
2007 Divestitures.  On July 17, 2007, we sold our approximate 50% non-operated working interest in several gas fields located in the LaSalle and Webb Counties of Texas for total cash proceeds of $40.1 million, resulting in a pre-tax gain on sale of $29.7 million.  The divested properties had estimated proved reserves of 2.3 MMBOE as of December 31, 2006, adjusted to the July 1, 2007 divestiture effective date, thereby yielding a sale price of $17.77 per BOE.  The June 2007 average daily net production from these fields was 0.8 MBOE/d.
 
During 2007, we sold our interests in several additional non-core properties for an aggregate amount of $12.5 million in cash for total estimated proved reserves of 0.6 MMBOE as of the divestitures’ effective dates.  The divested properties are located in Colorado, Louisiana, Michigan, Montana, New Mexico, North Dakota, Oklahoma, Texas and Wyoming.  The average daily net production from the divested property interests was 0.3 MBOE/d as of the dates of disposition.
 
2006 Acquisitions.  On August 29, 2006, we acquired a 15% working interest in approximately 170,000 acres of unproved properties in the central Utah Hingeline play for $25.0 million.  No producing properties or proved reserves were associated with this acquisition.  As part of this transaction, the operator agreed to pay 100% of our drilling and completion costs for the first three wells in the project.
 
On August 15, 2006, we acquired 65 producing properties, a gathering line, gas processing plant and 30,437 net acres of leasehold held by production in Michigan.  The purchase price was $26.0 million for estimated proved reserves of 1.4 MMBOE as of the acquisition effective date of May 1, 2006, resulting in a cost of $18.55 per BOE of estimated proved reserves.  Proved developed reserve quantities represented 99% of the total proved reserves acquired.  The average net production from the properties was 0.6 MBOE/d as of the acquisition effective date.  We operate 85% of the acquired properties.
 
 
We funded our 2006 acquisitions with cash on hand and borrowings under our credit agreement.
 
2006 Divestitures.  During 2006, we sold our interests in several non-core properties for an aggregate amount of $24.4 million in cash for total estimated proved reserves of 1.4 MMBOE as of the effective dates of the divestitures.  The divested properties included interests in the Cessford field in Alberta, Canada; Permian Basin of West Texas and New Mexico; and the Ashley Valley field in Uintah County, Utah.  The average net production from the divested property interests was 0.4 MBOE/d as of the effective dates of disposition, and we recognized a pre-tax gain on sale of $12.1 million related to these property sales.
 
Business Strategy 
 
Our goal is to generate meaningful growth in both production and free cash flow by investing in oil and gas projects with attractive rates of return on capital employed.  To date, we have achieved this goal largely through the acquisition of additional reserves as well as continued field development in our core areas.  Based on the extensive property base we have built, we now have several economically attractive opportunities to exploit and develop within our oil and gas properties and several opportunities to explore our acreage positions for production growth and additional proved reserves.  Specifically, we have focused, and plan to continue to focus, on the following:
 
Pursuing High-Return Organic Reserve Additions.  The development of large “resource plays” such as our Williston Basin and Piceance Basin projects has become one of our central objectives.  We have assembled 118,348 gross (83,033 net) acres on the eastern side of the Williston Basin in North Dakota in an active oil exploration play at our Robinson Lake prospect area, where the Middle Bakken reservoir is oil productive.  With the acquisition of Equity Oil Company in 2004, we acquired mineral interests and federal oil and gas leases in the Piceance Basin of Colorado, where we have found the Iles and Williams Fork reservoirs to be gas productive at our Boies Ranch prospect area and the Williams Fork reservoir to be gas productive at our Jimmy Gulch prospect area.  Our initial drilling results in both projects have been encouraging.  We have drilled five wells in our Robinson Lake acreage, which could support up to 90 locations on 1,280-acre spacing.  In the Piceance acreage, we have completed three wells and have identified 110 drilling locations based on 20-acre spacing.
 
Developing and Exploiting Existing Properties.  Our existing property base and our acquisitions over the past three years have provided us with numerous low-risk opportunities for exploitation and development drilling.  As of December 31, 2007, we have identified a drilling inventory of over 1,900 gross wells that we believe will add substantial production over the next five years.  Our drilling inventory consists largely of the development of our non-proved reserves on which we have spent significant time evaluating the costs and expected results.  Additionally, we have several opportunities to apply and expand enhanced recovery techniques that we expect will increase proved reserves and extend the productive lives of our mature fields.  In 2005, we acquired two large oil fields, the Postle field, located in the Oklahoma Panhandle, and the North Ward Estes field, located in the Permian Basin of West Texas.  We anticipate significant production increases in these fields over the next five years through the use of secondary and tertiary recovery techniques.  In these fields, we are actively injecting water and CO2 and executing extensive re-development, drilling and completion operations, as well as enhanced gas handling and treating capability.
 
Growing Through Accretive Acquisitions.  From 2004 to 2007, we completed 13 acquisitions of producing properties totaling 208.4 MMBOE of estimated total proved reserves, as of the respective acquisition effective dates.  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.  We intend to selectively acquire properties complementary to our core operating areas.
 
 
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.  We are also evaluating the sale of non-core properties.  We expect to use the net proceeds from the asset sales to repay debt under our credit agreement.  To support cash flow generation on our existing properties and help ensure expected cash flows from acquired properties, we periodically enter into derivative contracts.  Typically, we use costless collars to provide an attractive base commodity price level, while maintaining the ability to benefit from improvements in commodity prices. 
 
Competitive Strengths
 
We believe that our key competitive strengths lie in our balanced asset portfolio, our experienced management and technical team and our commitment to effective application of new technologies.
 
Balanced, Long-Lived Asset Base.  As of December 31, 2007, we had interests in 8,458 gross (3,565 net) productive wells across 934,723 gross (481,647 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 in executing our strategy because we are not dependent on any particular producing regions or geological formations.  As a result of our acquisitions of the Postle and North Ward Estes properties in 2005, we have enhanced the production stability and reserve life of our developed reserves.  Additionally, these properties contain identified growth opportunities that we expect will significantly increase production.
 
Experienced Management Team.  Our management team averages 25 years of experience in the oil and gas industry.  Our personnel have extensive experience in each of our core geographical areas and in all of our operational disciplines.  In addition, each of our acquisition professionals has at least 26 years of experience in the evaluation, acquisition and operational assimilation of oil and gas properties.
 
Commitment to Technology.  In each of our core operating areas, we have accumulated detailed geologic and geophysical knowledge and have developed significant technical and operational expertise.  In recent years, we have developed considerable expertise in conventional and 3-D seismic imaging and interpretation.  Our technical team has access to approximately 5,694 square miles of 3-D seismic data, digital well logs and other subsurface information.  This data is analyzed with advanced geophysical and geological computer resources dedicated to the accurate and efficient characterization of the subsurface oil and gas reservoirs that comprise our asset base.
 
In addition, our information systems enable us to update our production databases through daily uploads from hand held computers in the field.  With the acquisition of the Postle and North Ward Estes properties, we have assembled a team of 14 professionals averaging over 26 years of expertise in managing CO2 floods.  This provides us with the ability to pursue other CO2 flood targets and employ this technology to add reserves to our portfolio.  This commitment to technology has increased the productivity and efficiency of our field operations and development activities.
 
 
Proved Reserves
 
Our estimated proved reserves as of December 31, 2007 are summarized in the table below.
 
   
Oil
(MMbbl)
   
Natural Gas
(Bcf)
   
Total
(MMBOE)
   
% of Total
Proved
   
Future Capital Expenditures
(In millions)
 
Permian Basin:
                             
PDP
    30.7       41.7       37.6       33 %      
PDNP
    21.2       8.5       22.6       20 %      
PUD
    48.8       25.8       53.2       47 %      
Total Proved
    100.7       76.0       113.4       100 %   $ 704.0  
                                         
Rocky Mountains:
                                       
PDP
    34.9       68.6       46.4       75 %        
PDNP
    1.3       15.5       3.9       6 %        
PUD
    6.0       32.8       11.4       19 %        
Total Proved
    42.2       116.9       61.7       100 %   $ 160.6  
                                         
Mid-Continent:
                                       
PDP
    27.4       23.9       31.4       61 %        
PDNP
    6.6       2.8       7.1       14 %        
PUD
    12.0       3.9       12.6       25 %        
Total Proved
    46.0       30.6       51.1       100 %   $ 264.7  
                                         
Gulf Coast:
                                       
PDP
    2.1       29.7       7.1       58 %        
PDNP
    0.3       5.0       1.1       9 %        
PUD
    1.1       17.8       4.1       33 %        
Total Proved
    3.5       52.5       12.3       100 %   $ 41.1  
                                         
Michigan:
                                       
PDP
    1.7       37.5       7.9       64 %        
PDNP
    1.1       3.8       1.7       14 %        
PUD
    1.1       9.4       2.7       22 %        
Total Proved
    3.9       50.7       12.3       100 %   $ 16.4  
                                         
Total Company:
                                       
PDP
    96.8       201.4       130.4       52 %        
PDNP
    30.5       35.6       36.4       15 %        
PUD
    69.0       89.7       84.0       33 %        
Total Proved
    196.3       326.7       250.8       100 %   $ 1,186.8  


Marketing and Major Customers
 
We principally sell our oil and gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities.  In areas where there is no practical access to pipelines, oil is trucked to storage facilities.  Our marketing of oil and gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted.  During 2007, sales to Plains Marketing LP and Valero Energy Corporation accounted for 13% and 14%, respectively, of our total oil and natural gas sales.  During 2006, sales to Plains Marketing LP and Valero Energy Corporation accounted for 16% and 12%, respectively, of our total oil and natural gas sales.  During 2005, sales to Teppco Crude Oil LLC accounted for 10% of our total oil and natural gas sales.
 
 
Title to Properties
 
Our properties are subject to customary royalty interests, liens under indebtedness, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions.  Our credit agreement is also secured by a first lien on substantially all of our assets.  We do not believe that any of these burdens materially interfere with the use of our properties in the operation of our business.
 
We believe that we have satisfactory title to or rights in all of our producing properties.  As is customary in the oil and gas industry, minimal investigation of title is made at the time of acquisition of undeveloped properties.  In most cases, we investigate title and obtain title opinions from counsel only when we acquire producing properties or before commencement of drilling operations.
 
Competition
 
We operate in a highly competitive environment for acquiring properties, marketing oil and gas and securing trained personnel.  Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate.  Those companies may be able to pay more for productive oil and gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit.  Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.  Also, there is substantial competition for capital available for investment in the oil and gas industry.
 
Regulation
 
Regulation of Transportation, Sale and Gathering 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.
 
A final rule was implemented by the U.S. Department of Transportation on March 15, 2006 that defines and puts new safety requirements on gas gathering pipelines.  We are screening all of our pipeline systems to determine if the new rules apply.  In addition, many state agencies have adopted these new federal regulations.  As the agencies continue to work on interpreting the definitions in the rule, we continue to evaluate which pipelines may be subject to the new regulations.  These new regulations may put some of our gas gathering lines under the same level of scrutiny that transmission lines have seen in the past.  The new regulations impose additional costly regulatory requirements on previously unregulated pipelines.
 
Regulation of Transportation of Oil
 
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices.  Nevertheless, Congress could reenact price controls in the future.
 
Our sales of crude oil are affected by the availability, terms and cost of transportation.  The transportation of oil in common carrier pipelines is also subject to rate regulation.  The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act.  In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances.  Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for crude oil transportation rates that allowed for an increase or decrease in the cost of transporting oil to the purchaser.  A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines.  As a result, the FERC in February 2003 increased the index slightly, effective July 2001.  Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions.  The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state.  Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.
 
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis.  Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates.  When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs.  Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
 
 
Regulation of Production
 
The production of oil and gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations.  Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations.  All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum allowable rates of production from oil and gas wells, the regulation of well spacing, and plugging and abandonment of wells.  The effect of these regulations is to limit the amount of oil and gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing.  Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, gas and natural gas liquids within its jurisdiction.
 
Some of our offshore operations are conducted on federal leases that are administered by Minerals Management Service, or MMS, and are required to comply with the regulations and orders issued by MMS under the Outer Continental Shelf Lands Act.  Among other things, we are required to obtain prior MMS approval for any exploration plans we pursue and our development and production plans for these leases.  MMS regulations also establish construction requirements for production facilities located on our federal offshore leases and govern the plugging and abandonment of wells and the removal of production facilities from these leases.  Under limited circumstances, MMS could require us to suspend or terminate our operations on a federal lease.
 
MMS also establishes the basis for royalty payments due under federal oil and gas leases through regulations issued under applicable statutory authority.  State regulatory authorities establish similar standards for royalty payments due under state oil and gas leases.  The basis for royalty payments established by MMS and the state regulatory authorities is generally applicable to all federal and state oil and gas lessees.  Accordingly, we believe that the impact of royalty regulation on our operations should generally be the same as the impact on our competitors.
 
The failure to comply with these rules and regulations can result in substantial penalties.  Our competitors in the oil and gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
 
Environmental Regulations
 
General.  Our oil and gas exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection.  Numerous governmental agencies, such as the U.S. Environmental Protection Agency (the “EPA”) issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or that may result in injunctive relief for failure to comply.  These laws and regulations may require the acquisition of a permit before drilling or facility construction commences, restrict the types, quantities and concentrations of various materials that can be released into the environment in connection with drilling and production activities, limit or prohibit project siting, construction, or drilling activities on certain lands laying within wilderness, wetlands, ecologically sensitive and other protected areas, require remedial action to prevent pollution from former operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations.  The EPA and analogous state agencies may delay or refuse the issuance of required permits or otherwise include onerous or limiting permit conditions that may have a significant adverse impact on our ability to conduct operations.  The regulatory burden on the oil and gas industry increases the cost of doing business and consequently affects its profitability.
 
 
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly material handling, storage, transport, disposal or cleanup requirements could materially and adversely affect our operations and financial position, as well as those of the oil and gas industry in general.  While we believe that we are in substantial compliance with current applicable environmental laws and regulations and have not experienced any material adverse effect from compliance with these environmental requirements, there is no assurance that this trend will continue in the future.
 
The environmental laws and regulations which have the most significant impact on the oil and gas exploration and production industry are as follows:
 
Superfund.  The Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as “CERCLA” or “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment.  These persons include the “owner” or “operator” of a disposal site or sites where a release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site.  Under CERCLA, such persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.  In the course of our ordinary operations, we may generate material that may fall within CERCLA’s definition of a “hazardous substance.”  Consequently, we may be jointly and severally liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these materials have been disposed or released.
 
We currently own or lease, and in the past have owned or leased, properties that for many years have been used for the exploration and production of oil and gas.  Although we and our predecessors have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other materials may have been disposed or released on, under, or from the properties owned or leased by us or on, under, or from other locations where these hydrocarbons and materials have been taken for disposal.  In addition, many of these owned and leased properties have been operated by third parties whose management and disposal of hydrocarbons and materials were not under our control.  Similarly, the disposal facilities where discarded materials are sent are also often operated by third parties whose waste treatment and disposal practices may not be adequate.  While we only use what we consider to be reputable disposal facilities, we might not know of a potential problem if the disposal occurred before we acquired the property or business, if the problem itself is not discovered until years later.  Our properties, adjacent affected properties, the disposal sites, and the material itself may be subject to CERCLA and analogous state laws.  Under these laws, we could be required:
 
·  
to remove or remediate previously disposed materials, including materials disposed or released by prior owners or operators or other third parties;
·  
to clean up contaminated property, including contaminated groundwater; or
·  
to perform remedial operations to prevent future contamination, including the plugging and abandonment of wells drilled and left inactive by prior owners and operators.
 
At this time, we do not believe that we are a potentially responsible party with respect to any Superfund site and we have not been notified of any claim, liability or damages under CERCLA.
 
 
Oil Pollution Act.  The Oil Pollution Act of 1990, also known as “OPA,” and regulations issued under OPA impose strict, joint and several liability on “responsible parties” for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States.  A “responsible party” includes the owner or operator of an onshore facility and the lessee or permittee of the area in which an offshore facility is located.  The OPA establishes a liability limit for onshore facilities of $350.0 million, while the liability limit for offshore facilities is the payment of all removal costs plus up to $75.0 million in other damages, but these limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a cleanup.  The OPA also requires the lessee or permittee of the offshore area in which a covered offshore facility is located to establish and maintain evidence of financial responsibility in the amount of $35.0 million ($10.0 million if the offshore facility is located landward of the seaward boundary of a state) to cover liabilities related to an oil spill for which such person is statutorily responsible.  The amount of financial responsibility required under OPA may be increased up to $150.0 million, depending on the risk represented by the quantity or quality of oil that is handled by the facility.  Any failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to administrative, civil or criminal enforcement actions.  We believe we are in compliance with all applicable OPA financial responsibility obligations.  Moreover, we are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on us.
 
Resource Conservation Recovery Act.  The Resource Conservation and Recovery Act, also known as “RCRA,” is the principal federal statute governing the treatment, storage and disposal of hazardous wastes.  RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility.  RCRA and many state counterparts specifically exclude from the definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy” and thus we are not required to comply with a substantial portion of RCRA’s requirements because our operations generate minimal quantities of hazardous wastes.  However, these wastes may be regulated by EPA or state agencies as solid waste.  In addition, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils, may be regulated as hazardous waste.  Although we do not believe the current costs of managing our materials constituting wastes as they are presently classified to be significant, any repeal or modification of the oil and gas exploration and production exemption by administrative, legislative or judicial process, or modification of similar exemptions in analogous state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses.
 
Clean Water Act.  The Federal Water Pollution Control Act of 1972, or the Clean Water Act (the “CWA”), imposes restrictions and controls on the discharge of produced waters and other pollutants into navigable waters.  Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands.  The CWA and certain state regulations prohibit the discharge of produced water, sand, drilling fluids, drill cuttings, sediment and certain other substances related to the oil and gas industry into certain coastal and offshore waters without an individual or general National Pollutant Discharge Elimination System discharge permit.
 
 
Historically, the EPA had regulations under the authority of the CWA that required certain oil and gas exploration and production projects to obtain permits for construction projects with storm water discharges.  However, the Energy Policy Act of 2005 nullified most of the EPA regulations that required permitting of oil and gas construction projects.  There are still some States that regulate the discharge of storm water from oil and gas construction projects.  Costs may be associated with the treatment of wastewater and/or developing and implementing storm water pollution prevention plans.  The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.  In Section 40 CFR 112 of the regulations, the EPA promulgated the Spill Prevention, Control, and Countermeasure, or SPCC, regulations, which require certain oil containing facilities to prepare plans and meet construction and operating standards.  The SPCC regulations were revised in 2002 and will require the amendment of SPCC plans and the modification of spill control devices at many facilities.  The due date for having plans completed and control devices in place was extended on December 12, 2005 with the new compliance date being October 31, 2007.  On May 16, 2007 the EPA extended the compliance dates until July 1, 2009 for both completion and implementation of the plan.  The extension will allow time for the EPA to complete additional rule amendments and guidance documents.  On October 15, 2007 the EPA proposed amendments to the 2002 SPCC rule to provide increased clarity, to tailor requirements to particular industry sectors, and to streamline certain requirements for a facility owner or operator subject to the rule.  The EPA expects to finalize this proposed rule by the summer of 2008.  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 Act restricts the emission of air pollutants from many sources, including oil and gas operations.  New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance.  More stringent regulations governing emissions of toxic air pollutants are being developed by the EPA, and may increase the costs of compliance for some facilities.  We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold or have applied for all permits necessary to our operations.
 
Global Warming and Climate Control.  Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere.  In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases.  In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.  Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases.  The Court’s holding in Massachusetts that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs.  New legislation or regulatory programs that restrict emissions of greenhouse gases in areas where we operate could adversely affect demand for oil and gas products that, in turn, could have a significant impact on our operations.
 
Consideration of Environmental Issues in Connection with Governmental Approvals.  Our operations frequently require licenses, permits and/or other governmental approvals.  Several federal statutes, including the Outer Continental Shelf Lands Act, the National Environmental Policy Act, and the Coastal Zone Management Act require federal agencies to evaluate environmental issues in connection with granting such approvals and/or taking other major agency actions.  The Outer Continental Shelf Lands Act, for instance, requires the U.S. Department of Interior to evaluate whether certain proposed activities would cause serious harm or damage to the marine, coastal or human environment.  Similarly, the National Environmental Policy Act requires the Department of Interior and other federal agencies to evaluate major agency actions having the potential to significantly impact the environment.  In the course of such evaluations, an agency would have to prepare an environmental assessment and, potentially, an environmental impact statement.  The Coastal Zone Management Act, on the other hand, aids states in developing a coastal management program to protect the coastal environment from growing demands associated with various uses, including offshore oil and gas development.  In obtaining various approvals from the Department of Interior, we must certify that we will conduct our activities in a manner consistent with these regulations.
 
 
Employees
 
As of December 31, 2007, we had 412 full-time employees, including 29 senior level geoscientists and 38 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
 
Each of the risks described below should be carefully considered, together with all of the other information contained in this Annual Report on Form 10-K, before making an investment decision with respect to our securities.  If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially and adversely affected and you may lose all or part of your investment.
 
A substantial or extended decline in oil and gas prices may adversely affect our business, financial condition, results of operations or cash flows.
 
The price we receive for our oil and gas production heavily influences our revenue, profitability, access to capital and future rate of growth.  Crude oil and natural gas are commodities, and therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.  Historically, the markets for oil and gas have been volatile.  These markets will likely continue to be volatile in the future.  The prices we receive for our production and the levels of our production depend on numerous factors beyond our control.  These factors include, but are not limited to, the following:
 
 
changes in global supply and demand for oil and gas;
 
the actions of the Organization of Petroleum Exporting Countries;
 
the price and quantity of imports of foreign oil and gas;
 
political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity;
 
the level of global oil and gas exploration and production activity;
 
the level of global oil and gas inventories;
 
weather conditions;
 
technological advances affecting energy consumption;
 
domestic and foreign governmental regulations;
 
proximity and capacity of oil and gas pipelines and other transportation facilities;
 
the price and availability of competitors’ supplies of oil and gas in captive market areas; and
 
the price and availability of alternative fuels.
 
 
 
Lower oil and gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and gas that we can produce economically.  A substantial or extended decline in oil or gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.  Lower oil and gas prices may also reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders based on the collateral value of our proved reserves that have been mortgaged to the lenders. 
 
Drilling for and producing oil and gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
 
Our future success will depend on the success of our development, exploitation, production and exploration activities.  Our oil and gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or gas production.  Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.  Please read ‘‘— Reserve estimates depend on many assumptions that may turn out to be inaccurate . . .” later in this Item 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, CO2 and qualified personnel;
 
equipment failures or accidents;
 
adverse weather conditions, such as hurricanes and storms;
 
reductions in oil and gas prices; and
 
title problems.

Prospects that we decide to drill may not yield oil or gas in commercially viable quantities. 
 
We describe some of our current prospects and our plans to explore those prospects in this Annual Report on Form 10-K.  A prospect is a property on which we have identified what our geoscientists believe, based on available seismic and geological information, to be indications of oil or gas.  Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation.  There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or gas in sufficient quantities to recover drilling or completion costs or to be economically viable.  The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or gas will be present or, if present, whether oil or gas will be present in commercial quantities.  The analogies we draw from available data from other wells, more fully explored prospects or producing fields may not be applicable to our drilling prospects.  We may terminate our drilling program for a prospect if results do not merit further investment. 
 
 
Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. 
 
We have specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage.  As of December 31, 2007, we had identified and scheduled over 1,900 gross drilling locations.  These scheduled drilling locations represent a significant part of our growth strategy.  Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability of capital, costs of oil field goods and services, drilling results, regulatory approvals and other factors.  Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations.  As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business. 
 
We have been an early entrant into new or emerging plays; as a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful. 
 
While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a developing play, our drilling results in these areas are more uncertain than drilling results in areas that are developed and producing.  Since new or emerging plays have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results.  Therefore, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.
 
Our use of enhanced recovery methods creates uncertainties that could adversely affect our results of operations and financial condition. 
 
One of our business strategies is to commercially develop oil reservoirs using enhanced recovery technologies.  For example, we inject water and CO 2 into formations on some of our properties to increase the production of oil and natural gas.  The additional production and reserves attributable to the use of these enhanced recovery methods are inherently difficult to predict.  If our enhanced recovery programs do not allow for the extraction of oil and natural gas in the manner or to the extent that we anticipate, our future results of operations and financial condition could be materially adversely affected.  Additionally, our ability to utilize CO2 as an enhanced recovery technique is subject to our ability to obtain sufficient quantities of CO2.  Our CO2 contracts permit the suppliers to reduce the amount of CO2 they provide to us in certain circumstances.  If this occurs, we may not have sufficient CO2 to produce oil and natural gas in the manner or to the extent that we anticipate.  These contracts are also structured as “take-or-pay” arrangements, which require us to continue to make payments even if we decide to terminate or reduce our use of CO2 as part of our enhanced recovery techniques.
 
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 completed or future acquisitions: 
 
 
 
some of the acquired businesses or properties may not produce revenues, reserves, earnings or cash flow at anticipated levels;
 
we may assume liabilities that were not disclosed to us or that exceed our estimates;
 
we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;
 
acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures; and
 
we may issue additional debt securities or equity related to future acquisitions.

The development of the proved undeveloped reserves in the North Ward Estes and Postle fields may take longer and may require higher levels of capital expenditures than we currently anticipate.
 
As of December 31, 2007, undeveloped reserves comprised 56% of the North Ward Estes field’s total estimated proved reserves and 27% of Postle field’s estimated total proved reserves.  To fully develop these reserves, we expect to incur total future development costs of $625.2 million at the North Ward Estes field and $258.7 million at the Postle field.  During 2007 and 2006, the estimated future capital expenditures necessary to develop the proved reserves at the North Ward Estes field and Postle field increased substantially.  The increases were due to several factors, including equipment and service cost inflation, higher CO2 unit costs and volumes, higher costs associated with the expanded scope of previously identified projects, as well as new projects identified during 2006.  Together, these fields encompass 75% of our estimated total future development costs related to proved reserves.  Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate.  In addition, the development of these reserves will require the use of enhanced recovery techniques, including water flood and CO2 injection installations, the success of which is less predictable than traditional development techniques.  Therefore, ultimate recoveries from these fields may not match current expectations. 
 
Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile. 
 
In order to finance acquisitions of additional producing properties, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments or other means.  These changes in capitalization may significantly affect our risk profile.  Additionally, significant acquisitions or other transactions can change the character of our operations and business.  The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties.  Furthermore, we may not be able to obtain external funding for future acquisitions or other transactions or to obtain external funding on terms acceptable to us. 
 
Properties that we acquire may not produce as projected, and we may be unable to identify liabilities associated with the properties or obtain protection from sellers against them.
 
Our business strategy includes a continuing acquisition program.  From 2004 to 2007, we completed 13 separate acquisitions of producing properties with a combined purchase price of $1,474.8 million for estimated proved reserves as of the effective dates of the acquisitions of 208.4 MMBOE.  The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following: 
 
 
the amount of recoverable reserves;
 
future oil and gas prices;
 
estimates of operating costs;
 
estimates of future development costs;
 
timing of future development costs;
 
estimates of the costs and timing of plugging and abandonment; and
 
potential environmental and other liabilities.
 
 
Our assessment will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies.  In the course of our due diligence, we may not inspect every well, platform or pipeline.  Inspections may not reveal structural and environmental problems, such as pipeline corrosion or groundwater contamination, when they are made.  We may not be able to obtain contractual indemnities from the seller for liabilities that it created.  We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. 
 
If oil and gas prices decrease, we may be required to take write-downs of the carrying values of our oil and gas properties. 
 
Accounting rules require that we review periodically the carrying value of our oil and gas properties for possible impairment.  Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and gas properties.  A write-down constitutes a non-cash charge to earnings.  We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken. 
 
Our debt level and the covenants in the agreements governing our debt could negatively impact our financial condition, results of operations, cash flows and business prospects. 
 
As of December 31, 2007, we had $250.0 million in outstanding indebtedness under Whiting Oil and Gas Corporation’s (“Whiting Oil and Gas”) credit agreement with $650.0 million of available borrowing capacity, as well as $620.0 million of senior subordinated notes outstanding.  We are permitted to incur additional indebtedness, provided we meet certain requirements in the indentures governing our senior subordinated notes and Whiting Oil and Gas’ credit agreement. 
 
Our level of indebtedness and the covenants contained in the agreements governing our debt could have important consequences for our operations, including: 
 
 
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’ 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’ 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 debt under the credit agreement. 
 
 
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, and 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’ 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’ credit agreement contain various restrictive covenants that may potentially limit our management’s discretion in certain respects.  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 restricted 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’ 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’ 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 exploration and development operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our oil and gas reserves. 
 
The oil and gas industry is capital intensive.  We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of oil and gas reserves.  To date, we have financed capital expenditures primarily with bank borrowings and cash generated by operations.  We intend to finance our future capital expenditures with cash flow from operations and our existing financing arrangements.  Our cash flow from operations and access to capital are subject to a number of variables, including: 
 
 
 our proved reserves;
 
 the level of oil and gas we are able to produce from existing wells;
 
 the prices at which oil and gas are sold; and
 
 our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our bank credit agreement decreases as a result of lower oil and gas prices, operating difficulties, declines in reserves or for any other reason, then we may have limited ability to obtain the capital necessary to sustain our operations at current levels.  We may, from time to time, need to seek additional financing.  There can be no assurance as to the availability or terms of any additional financing. 
 
If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all.  If cash generated by operations or available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and gas reserves. 
 
Reserve estimates depend on many assumptions that may turn out to be inaccurate.  Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. 
 
The process of estimating oil and gas reserves is complex.  It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors.  Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves referred to in this report. 
 
In order to prepare our estimates, we must project production rates and timing of development expenditures.  We must also analyze available geological, geophysical, production and engineering data.  The extent, quality and reliability of this data can vary.  The process also requires economic assumptions about matters such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.  Therefore, estimates of oil and gas reserves are inherently imprecise.
 
Actual future production, oil and gas prices, revenues, taxes, exploration and development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from our estimates.  Any significant variance could materially affect the estimated quantities and present value of reserves referred to in this report.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. 
 
 
It should not be assumed that the present value of future net revenues from our proved reserves, as referred to in this report, is the current market value of our estimated oil and gas reserves.  In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate.  Actual future prices and costs may differ materially from those used in the present value estimate.  If natural gas prices decline by $0.10 per Mcf, then the standardized measure of discounted future net cash flows of our estimated proved reserves as of December 31, 2007 would have decreased from $4,011.7 million to $4,002.2 million.  If oil prices decline by $1.00 per Bbl, then the standardized measure of discounted future net cash flows of our estimated proved reserves as of December 31, 2007 would have decreased from $4,011.7 million to $3,959.8 million. 
 
Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. 
 
Oil and gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife.  In certain areas drilling and other oil and gas activities can only be conducted during the spring and summer months.  This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages.  Resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. 
 
The differential between the NYMEX or other benchmark price of oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial condition and cash flows. 
 
The prices that we receive for our oil and natural gas production sometimes trade at a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions.  The difference between the benchmark price and the price we receive is called a differential.  We cannot accurately predict oil and natural gas differentials.  Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial condition and cash flows.
 
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and gas operations. 
 
We are not insured against all risks.  Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.  Our oil and gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and gas, including the possibility of: 
 
 
environmental hazards, such as uncontrollable flows of oil, gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
 
abnormally pressured formations;
 
mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
 
fires and explosions;
 
personal injuries and death; and
 
natural disasters.
 
 
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to our company.  We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented.  In addition, pollution and environmental risks generally are not fully insurable.  If a significant accident or other event occurs and is not fully covered by insurance, then it could adversely affect us. 
 
We have limited control over activities on properties we do not operate, which could reduce our production and revenues. 
 
If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties.  The failure of an operator of our wells to adequately perform operations or an operator’s breach of the applicable agreements could reduce our production and revenues.  The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells, and use of technology.  Because we do not have a majority interest in most wells we do not operate, we may not be in a position to remove the operator in the event of poor performance. 
 
Our use of 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and gas, which could adversely affect the results of our drilling operations. 
 
Even when properly used and interpreted, 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures.  In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures.  Thus, 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 data 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 seismic data without having an opportunity to attempt to benefit from those expenditures. 
 
 Market conditions or operational impediments may hinder our access to oil and gas markets or delay our production. 
 
In connection with our continued development of oil and gas properties, we may be disproportionately exposed to the impact of delays or interruptions of production from wells in these properties, caused by transportation capacity constraints, curtailment of production or the interruption of transporting oil and gas volumes produced.  In addition, market conditions or a lack of satisfactory oil and gas transportation arrangements may hinder our access to oil and gas markets or delay our production.  The availability of a ready market for our oil and gas production depends on a number of factors, including the demand for and supply of oil and gas and the proximity of reserves to pipelines and terminal facilities.  Our ability to market our production depends substantially 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 access to natural gas pipelines, gathering systems or processing facilities may be limited or unavailable.  If that were to occur, then we would be unable to realize revenue from those wells until production arrangements were made to deliver the production to market.
 
 
We are subject to complex laws that can affect the cost, manner or feasibility of doing business.
 
 Exploration, development, production and sale of oil and gas are subject to extensive federal, state, local and international regulation.  We may be required to make large expenditures to comply with governmental regulations.  Matters subject to regulation include: 
 
 
 discharge permits for drilling operations;
 
 drilling bonds;
 
 reports concerning operations;
 
 the spacing of wells;
 
 unitization and pooling of properties; and
 
 taxation.

Under these laws, we could be liable for personal injuries, property damage and other damages.  Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties.  Moreover, these laws could change in ways that could 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 environmental laws and regulations.
 
 Our oil and gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection.  These laws and regulations may require the acquisition of a permit before drilling commences; restrict the types, quantities, and concentration of materials that can be released into the environment in connection with drilling and production activities; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas; and impose substantial liabilities for pollution resulting from our operations.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, incurrence of investigatory or remedial obligations, or the imposition of injunctive relief.  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. 
 
 Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly material handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance and may otherwise have a material adverse effect on our results of operations, competitive position, or financial condition as well as those of the oil and gas industry in general.  For instance, in response to studies suggesting that emissions of certain gases, commonly referred to as greenhouse gases and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere, the U.S. Congress is actively considering legislation, and more than a dozen states have already taken legal measures to reduce emission of these gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.  Moreover, the U.S. Supreme Court only recently held in a case,  Massachusetts, et al. v. EPA , that greenhouse gases fall within the federal Clean Air Act’s definition of “air pollutant,” which could result in the regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs.  New legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse affect on our operations and demand for our products. 
 
 
Unless we replace our oil and gas reserves, our reserves and production will decline, which would adversely affect our cash flows and results of operations. 
 
 
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 Senior Vice President; Rick A. Ross, our Vice President, Operations; Peter W. Hagist, our Vice President, Permian 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 our exploration and development plans on a timely basis or within our budget.
 
 Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploration and development operations, which could have a material adverse effect on our business, financial condition, results of operations or cash flows.
 
Competition in the oil and gas industry is intense, which may adversely affect our ability to compete.
 
 We operate in a highly competitive environment for acquiring properties, marketing oil and gas and securing trained personnel.  Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate.  Those companies may be able to pay more for productive oil and gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit.  Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.  Also, there is substantial competition for available capital for investment in the oil and gas industry.  We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital. 
 
 
Our use of oil and gas price hedging contracts involves credit risk and may limit future revenues from price increases and result in significant fluctuations in our net income. 
 
 We enter into hedging transactions of our oil and gas production to reduce our exposure to fluctuations in the price of oil and gas.  Our hedging transactions to date have consisted of financially settled crude oil and natural gas forward sales contracts, primarily costless collars, placed with major financial institutions.  As of December 31, 2007, we had contracts maturing in 2008 covering the sale of 330,000 barrels of oil per month.  As of December 31, 2007, we had no outstanding gas hedges, and all our oil hedges expire by December 2008.  See “Quantitative and Qualitative Disclosure about Market Risk” for pricing and a more detailed discussion of our hedging transactions.
 
We may in the future enter into these and other types of hedging arrangements to reduce our exposure to fluctuations in the market prices of oil and gas.  Hedging transactions expose us to risk of financial loss in some circumstances, including if production is less than expected, the other party to the contract defaults on its obligations or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.  Hedging transactions may limit the benefit we may otherwise receive from increases in the price for oil and gas.  Furthermore, if we do not engage in hedging transactions, then we may be more adversely affected by declines in oil and gas prices than our competitors who engage in hedging transactions.  Additionally, hedging transactions may expose us to cash margin requirements. 
 
Item 1B.
Unresolved Staff Comments
 
None.
 
Item 2.
Properties
 
Summary of Oil and Gas Properties and Projects
 
Permian Basin Region
 
Our Permian Basin operations include assets in Texas and New Mexico.  As of December 31, 2007, the Permian Basin region contributed 113.4 MMBOE (89% oil) of estimated proved reserves to our portfolio of operations, which represents 45% of our total estimated proved reserves and contributed 10.7 MBOE/d of average daily production in December 2007.  Approximately 96% of the proved reserves of our Permian Basin operations are related to properties in Texas.
 
North Ward Estes.  The North Ward Estes field includes six base leases with 100% working interest in 58,000 gross and net acres in Ward and Winkler Counties, Texas.  As of December 31, 2007, there were approximately 1,024 producing wells and 349 injection wells.  The Yates Formation at 2,600 feet is the primary producing zone with additional production from other zones including the Queen at 3,000 feet.  We also have the rights to deeper horizons under 34,140 gross acres in the North Ward Estes field.  The North Ward Estes properties produced at an estimated average net daily rate of 5.1 MBOE/d during the month of December 2007.  In the North Ward Estes field, the estimated proved reserves as of December 31, 2007 were 18% PDP, 26% PDNP and 56% PUD.
 
The North Ward Estes field was initially developed in the 1930’s and full scale waterflooding was initiated in 1955.  A CO2 enhanced recovery project was implemented in the core of the field in 1989, but was terminated in 1996 after a successful top lease by a third party.  We reinitiated water injection in 2006 and successfully re-pressured the pilot area.  We initiated CO2 injection into the pilot area on May 22, 2007.  In January 2008, we began expanding the CO2 flood from the pilot area into additional sections in the Phase 1 area.  By the end of January 2008, we were injecting CO2 at 120 MMcf/d, above the target rate of 100 MMcf/d of CO2.  In the fourth quarter of 2006, we began construction of a gas plant to process and separate the CO2 from the produced gas.  This plant is scheduled to start processing produced gas during the second quarter of 2008.
 
 
We also have interests in certain other fields within the Permian Basin of Texas and New Mexico, including 2,753 producing oil and gas wells.
 
Keystone South, Martin and Flying W Fields.  We own a 100% working interest and operate these three fields located on the Western edge of the Midland Basin.  Production comes from the Clearfork Formation, with additional production from the Wichita, Wolfcamp, Devonian, Silurian, McKee and Ellenburger Formations.  During 2007, we drilled three wells in the Martin field.  In 2008, we have three additional wells planned at Martin and a combination of seven additional new drills and recompletions planned in Keystone South and Flying W.
 
Rocky Mountain Region
 
Our Rocky Mountain operations include assets in the states of North Dakota, Montana, Colorado, Utah, Wyoming and California.  As of December 31, 2007, our estimated proved reserves in the Rocky Mountain region were 61.7 MMBOE (68% oil), which represented 25% of our total estimated proved reserves, and our December 2007 daily production averaged 14.8 MBOE/d.  Approximately 53% and 27% of the proved reserves of our Rocky Mountain operations are related to assets in North Dakota and Wyoming, respectively.
 
Robinson Lake Bakken Play.  The Bakken Formation is a low permeability, unconventional reservoir consisting of highly oil saturated shale, dolomite and fine grained sand.  Horizontal drilling and advanced stimulation techniques have been successfully employed in the drilling of hundreds of wells in the Elm Coulee field in Montana and more recently in the North Dakota portion of the Williston Basin.  In early 2005, we embarked on an aggressive leasing program and have acquired total acreage as of year-end 2007 of 118,348 gross (83,033 net) acres primarily in Mountrail County, North Dakota for the purpose of developing a Bakken resource drilling program.  As of year end 2007, we had drilled five and completed four wells, and currently have four rigs actively drilling.  For 2008, we are planning to expand our drilling program to as many as nine rigs.  We are planning to drill 30 to 40 operated Bakken wells during 2008.
 
In addition to the drilling program, we have begun construction of a gas plant to process the associated gas.  The first phase of this plant is scheduled to begin receiving gas in the second quarter of 2008.
 
In March 2007, we purchased an interest in the Parshall field, also located in Montrail County, North Dakota.  As of December 31, 2007, we owned 66,957 gross (13,470 net) acres in the Parshall area of mutual interest.  This field is operated by another operator and at the end of 2007, we had participated in the drilling and completion of 24 horizontal middle Bakken wells.  We expect to participate in the drilling of approximately 50 to 60 additional wells in the Parshall field during 2008.
 
Red River Gas Drilling Program.  In 2004, we began acquiring 3-D seismic data over several Red River Formation prospects in the deeper, gas bearing part of the Williston Basin for the purpose of defining structure and reservoir distribution.  To date, we have acquired nine 3-D seismic surveys in Billings, McKenzie and Williams Counties totaling 236 square miles, which we have used to target 12 new wells.  We are planning on drilling seven new wells in 2008.
 
 
Billings Nose Drilling Program.  We have established a high concentration of producing wells in the Billings Nose area of Billings County, North Dakota.  These assets include the Big Stick Madison Unit and North Elkhorn Ranch Unit along with much of the acreage located between these two fields.  We have acquired 44 square miles of 3-D seismic data in this area and have since identified multiple opportunities in a variety of reservoirs including the Red River, Duperow, Bakken and Mission Canyon Formations.  Our efforts in 2007 focused on the North Elkhorn Ranch Unit in Billings County, North Dakota.  Four horizontal wellbores were drilled into the Elkhorn Ranch member of the Mission Canyon.
 
Nisku A Drilling Program.  We made a significant exploration discovery in 2004 in western Billings County, North Dakota in the Nisku A zone and drilled ten wells in 2004.  Since the discovery, we have participated in eight casing exit wells and 49 grass root wells (six drilled in 2007).  We are currently investigating waterflooding the reservoir.  Modeling efforts are complete and we are researching methods to install the waterflood while minimizing the surface impact as much of this project is located in the Theodore Roosevelt National Grassland, administered by the U.S. Forest Service.
 
Green River Basin - Siberia Ridge.  Siberia Ridge is within the greater Wamsutter Arch area of Sweetwater County, Wyoming and produces from a continuous-phase gas accumulation in the Cretaceous Almond Formation at 10,500 feet.  In 2004, the spacing rules governing the well density in the Siberia Ridge field were adjusted to allow for up to two wells per 160 acres.  This new configuration resulted in a total of 44 additional potential locations on our acreage.  Because of lease stipulations on this Federal acreage, drilling operations can begin on or after August 1st and must end by February 1st of the following year.  We have been able to maintain a single well drilling program by moving the rig between Anderson Canyon (described below) and Siberia Ridge.
 
Our development program commenced in mid-2005 and continued in 2006 with the drilling of ten new wells.  During 2007, an additional four wells were drilled.  Although not budgeted currently, there is potential for additional drilling later in 2008 once the lease stipulations allow drilling operations to resume.
 
Green River Basin - Anderson Canyon.  Anderson Canyon, North Anderson Canyon, Bird Canyon, and McDonald Draw fields are all located on the LaBarge Platform in Southwest Wyoming.  We drilled six wells in 2006 and an additional 21 in 2007.  We made improvements in the drilling operations, reducing the drill time from 20 days in 2006 to around nine days in 2007.  We are continuing to work on refining the completion operations in an attempt to optimize the resulting production and reserves.
 
Sulphur Creek - Boies Ranch Area, Rio Blanco County, Colorado.  The Sulphur Creek Area in the North Central Piceance Basin has the potential to be a focal point of our activity through 2009.  We acquired mineral interests and federal oil and gas leases in the 2004 Equity Oil Company acquisition.  As of year end 2007, we owned 16,893 gross (4,072 net) acres in the Boies Ranch and Jimmy Gulch properties in Rio Blanco County, Colorado.  We are currently supplementing our leasehold in the area.  Drilling by third parties near our leasehold demonstrated the presence of a continuous-phase gas resource in the Williams Fork Formation with up-hole potential in the Wasatch Formation.  We drilled and completed three gas producing wells early in 2007, and during the third quarter of 2007, we moved in two rigs and drilled an additional six wells that were awaiting completion operations by year end.  The rigs we moved in were specifically designed to allow numerous wells to be drilled from a pad, to reduce the footprint and surface impact.  Our plans for 2008 are to have a minimum of two drilling rigs running full time in the Piceance Basin and to drill 24 twenty-acre locations on the Boies Ranch and Jimmy Gulch acreage.
 
Utah Hingeline.  We own a 15%, non-operated, working interest in approximately 170,000 acres of leasehold in the central Utah Hingeline play.  This acreage covers several prospect leads which have been identified along trend with the recent Covenant field discovery in Sevier County, Utah.  As part of our acquisition of this property, the operator agreed to pay 100% our drilling and completion costs for the first three wells in the project.  The first two wells have been drilled on the acreage.  The first well, the Joseph Prospect, was a dry hole.  The second well, the Parowan Prospect, has been drilled, cased and temporarily abandoned pending resumed operations after lease stipulations allow operations to continue early in the third quarter of 2008.
 
 
Mid-Continent Region
 
Our Mid-Continent operations include assets in Oklahoma, Arkansas and Kansas.  As of December 31, 2007, the Mid-Continent region contributed 51.1 MMBOE (90% oil) of proved reserves to our portfolio of operations, which represented 20% of our total estimated proved reserves and contributed 7.2 MBOE/d of average daily production in December 2007.  The majority of the proved value within our Mid-Continent operations is related to properties in the Postle field.
 
Postle Field.  The Postle field, located in Texas County, Oklahoma, includes six producing units and one producing lease covering a total of approximately 25,600 gross (24,223 net) acres with working interests of 94% to 100%.  Four of the units are currently active CO2 enhanced recovery projects.  As of December 31, 2007, we were injecting 111 MMcf/d of CO2 and surpassed 120 MMcf/d in January 2008.  The Postle field is the largest Morrow oil field in the U.S.  The Postle properties produced at an estimated average net daily rate of 5.8 MBOE/d during the month of December 2007.  In the Postle field, the estimated proved reserves as of December 31, 2007 were 58% PDP, 15% PDNP and 27% PUD.
 
The Postle field was initially developed in the early 1960’s and unitized for waterflood in 1967.  Enhanced recovery projects in the three eastern units using CO2 was initiated in 1995.  During 2007, we expanded CO2 injection into the southern part of the fourth unit, HMU.  Operations are underway to expand CO2 injection into the northern part of HMU and to optimize flood patterns in the existing CO2 floods, with two drilling rigs and six workover rigs in the field.  These expansion projects include the restoration of shut-in wells and the drilling of new producing and injection wells.
 
We are the sole owner of the Dry Trails Gas Plant located in the Postle field.  This gas processing plant separates CO2 gas from the produced wellhead mixture of hydrocarbon and CO2 gas, so that the CO2 gas can be re-injected into the producing formation.  Construction began in mid-2006 to increase the plant capacity from its current capacity of 40.0 MMcf/d to 80.0 MMcf/d.  Construction is continuing and the plant expansion will utilize a membrane technology to separate the CO2 from the hydrocarbon gas.  The expansion is scheduled to be on line during second quarter 2008.
 
In addition to the producing assets and processing plant, we have a 60% interest in the 120 mile TransPetco operated CO2 transportation pipeline, thereby assuring the delivery of CO2 to the Postle field at a fair tariff.  A long-term CO2 purchase agreement was executed in 2005 to provide the necessary CO2 for the expansion planned in the field.
 
Gulf Coast Region
 
Our Gulf Coast operations include assets located in Texas, Louisiana and Mississippi.  As of December 31, 2007, the Gulf Coast region contributed 12.3 MMBOE (29% oil) of proved reserves to our portfolio of operations, which represented 5% of our total estimated proved reserves and contributed 4.1 MBOE/d of average daily production in December 2007.  Approximately 79% of the proved reserves of our Gulf Coast operations are related to properties in Texas.
 
Edwards Trend.  We own 21,950 gross (21,870 net) acres in the Word North, Yoakum, Kawitt, Sweet Home, and Three Rivers fields along the Edwards Trend in Karnes, Dewitt and Lavaca Counties, Texas.  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 2007, we farmed out interests in the Edwards to two different operators.  One of these operators utilized vertical wells to access the Edwards reservoir at approximately 12,000 feet.  The second operator is utilizing horizontal wellbores with swell packers to provide zonal isolation along the length of the wellbore.  Results from the horizontal wellbores look encouraging.  The farmout agreement required the drilling of four wells in the farmout acreage and the fourth well is just being completed.  Additional horizontal wells are being planned for 2008.
 
In 2008, we shot a 34 square mile 3-D seismic survey along the trend in our South Runge Prospect where we own 9,054 gross (7,643 net) acres, prospecting for expanded Wilcox.  We believe the results of the seismic shoot were promising, and three wells targeting the Wilcox are planned during early 2008.
 
Vicksburg Trend.  Our non-operated holdings in the Vicksburg and Frio Trends are concentrated primarily in the South Midway field in San Patricio County, Texas and the Agua Dulce field.  During 2005, we drilled or participated in eleven new wells targeting multiple gas productive sands in the Vicksburg and Frio Formations at depths between 10,000 and 14,500 feet.  Results from this program encouraged us to drill seven wells in South Midway and one well in Agua Dulce during 2006 and to participate in the drilling of five additional wells in South Midway during 2007.  In 2008, we plan to participate in three more wells in these fields.
 
Michigan Region
 
As of December 31, 2007, our estimated proved reserves in the Michigan region were 12.3 MMBOE (32% oil), and our December 2007 daily production averaged 3.5 MBOE/d.  Production in Michigan can be divided into two groups.  The majority of the reserves are in non-operated Antrim Shale wells located in the northern part of the state.  The remainder of the Michigan reserves are typified by more conventional oil and gas production located in the central and southern parts of the state.  We also operate the West Branch and Reno gas processing plants.  These plants are in good mechanical condition and capable of handling additional production.  The West Branch Plant gathers production from the Clayton, West Branch and other smaller fields.
 
Antrim Production.  In northern Michigan, we own an interest in over 50 multi-well Antrim Shale gas projects with proved producing reserves and ongoing development drilling.  During 2007, we participated in the drilling and completion of 19 Antrim Shale wells.  In 2008, we plan to continue to pursue similar development drilling opportunities.
 
Clayton Unit.  Clayton Unit production is primarily from the Prairie du Chien and Glenwood at a depth of around 11,000 feet.  During late 2005, we drilled two Glenwood/Prairie du Chien (“PdC”) wells in the Clayton Unit.  The target reservoir was the upper PdC, which historically had been the pay interval in the field.  Both of these wells encountered hydrocarbons in the Middle interval of the PdC, which had not previously produced.  The initial completion in both of these wells was in the middle PdC and both wells still have the original target reservoir behind pipe.  We have been encouraged by the results.  We have an eight well commitment with the drilling contractor and we are just finishing up well number six.  In Missaukee, Oseceola and Clare Counties, Michigan, we are in the process of permitting and shooting a 37 square mile 3-D seismic shoot prospecting for additional PdC and Glenwood accumulations.  This data acquisition should be complete by second quarter 2008 and lead to additional drilling later in the year.
 
Acreage
 
The following table summarizes gross and net developed and undeveloped acreage at December 31, 2007 by state.  Net acreage is our percentage ownership of gross acreage.  Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.
 
 
   
Developed Acreage
   
Undeveloped Acreage
   
Total Acreage
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
California
    35,698       10,707       2,333       50       38,031       10,757  
Colorado
    34,852       17,285       35,266       8,455       70,118       25,740  
Louisiana
    40,143       10,589       4,863       2,532       45,006       13,121  
Michigan
    140,331       61,462       32,524       25,869       172,855       87,331  
Montana
    40,161       13,183       41,814       19,622       81,975       32,805  
North Dakota
    188,550       99,777       327,868       188,377       516,418       288,154  
Oklahoma
    79,569       51,400       2,692       2,317       82,261       53,717  
Texas
    234,079       141,490       76,110       61,118       310,189       202,608  
Utah
    20,237       11,497       221,117       48,067       241,354       59,564  
Wyoming
    105,205       55,961       70,045       44,378       175,250       100,339  
Other*
    15,898       8,296       1,070       786       16,968       9,082  
Total
    934,723       481,647       815,702       401,571       1,750,425       883,218  

* Other includes Alabama, Arkansas, Mississippi, Nebraska and New Mexico.
 
Production History
 
The following table presents historical information about our produced oil and gas volumes:
 
   
Year Ended December 31,
 
   
2007
   
2006
   
2005
 
Oil production (MMbbls)
    9.6       9.8       7.0  
Natural gas production (Bcf)
    30.8       32.1       30.3  
Total production (MMBOE)
    14.7       15.2       12.1  
Daily production (MBOE/d)
    40.3       41.5       33.1  
Average sales prices:
                       
Oil (per Bbl)
  $ 64.57     $ 57.27     $ 51.26  
Effect of oil hedges on average price (per Bbl)
    (2.21 )     (0.95 )     (2.72 )
Oil net of hedging (per Bbl)
  $ 62.36     $ 56.32     $ 48.54  
                         
Natural gas (per Mcf)
  $ 6.19     $ 6.59     $ 7.03  
Effect of natural gas hedges on average price (per Mcf)
    -       0.06       (0.47 )
Natural gas net of hedging (per Mcf)
  $ 6.19     $ 6.65     $ 6.56  
                         
Per BOE data:
                       
Sales price (net of hedging)
  $ 53.57     $ 50.52     $ 44.70  
Lease operating expenses
  $ 14.20     $ 12.12     $ 9.24  
Production taxes
  $ 3.56     $ 3.11     $ 2.99  
Depreciation, depletion and amortization expenses
  $ 13.11     $ 10.74     $ 8.08  
General and administrative expenses
  $ 2.66     $ 2.49     $ 2.53  
 
 
 
Productive Wells
 
The following table presents our ownership at December 31, 2007 in productive oil and gas wells by region (a net well is our percentage ownership of a gross well).
 
   
Oil Wells
   
Natural Gas Wells
   
Total Wells(1)
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Permian Basin
    3,646       1,778       374       131       4,020       1,909  
Rocky Mountains
    1,711       406       405       199       2,116       605  
Mid-Continent
    470       312       211       93       681       405  
Gulf Coast
    93       56       436       129       529       185  
Michigan
    81       57       1,031       404       1,112       461  
Total
    6,001       2,609       2,457       956       8,458       3,565  

 
(1)
168 wells are multiple completions.  These 168 wells contain a total of 365 completions.  One or more completions in the same bore hole are counted as one well

Drilling Activity
 
We are engaged in numerous drilling activities on properties presently owned and intend to drill or develop other properties acquired in the future.  The following table sets forth 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
 
2007:
                                   
Development
    262       5       267       128.6       3.8       132.4  
Exploratory
    9       1       10       6.1       0.1       6.2  
Total                             
    271       6       277       134.7       3.9       138.6  
2006:
                                               
Development
    401       14       415       300.6       9.0       309.6  
Exploratory
    17       5       22       10.2       2.3       12.5  
Total
    418       19       437       310.8       11.3       322.1  
2005:
                                               
Development
    276       18       294       164.7       10.6       175.3  
Exploratory
    7       7       14       1.3       3.9       5.2  
Total
    283       25       308       166.0       14.5       180.5  

Item 3.
Legal Proceedings
 
Whiting is subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business.  It is management’s opinion that all claims and litigation we are involved in are not likely to have a material adverse effect on our consolidated financial position, cash flows or results of operations.
 
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 2007.
 
 
EXECUTIVE OFFICERS OF THE REGISTRANT
 
The following table sets forth certain information, as of February 15, 2008, regarding the executive officers of Whiting Petroleum Corporation:
 
Name
Age
Position
     
James J. Volker
61
Chairman, President and Chief Executive Officer
James T. Brown
55
Senior Vice President, Operations
Bruce R. DeBoer
55
Vice President, General Counsel and Corporate Secretary
Heather M. Duncan
37
Vice President, Human Resources
J. Douglas Lang
58
Vice President, Reservoir Engineering/Acquisitions
Rick A. Ross
49
Vice President, Operations
David M. Seery
53
Vice President, Land
Michael J. Stevens
42
Vice President and Chief Financial Officer
Mark R. Williams
51
Vice President, Exploration and Development
Brent P. Jensen
38
Controller and Treasurer

The following biographies describe the business experience of our executive officers:
 
James J. Volker joined us in August 1983 as Vice President of Corporate Development and served in that position through April 1993.  In March 1993, he became a contract consultant to us and served in that capacity until August 2000, at which time he became Executive Vice President and Chief Operating Officer.  Mr. Volker was appointed President and Chief Executive Officer and a director in January 2002 and Chairman of the Board in January 2004.  Mr. Volker was co-founder, Vice President and later President of Energy Management Corporation from 1971 through 1982.  He has over thirty years of experience in the oil and gas industry.  Mr. Volker has a degree in finance from the University of Denver, an MBA from the University of Colorado and has completed H. K. VanPoolen and Associates’ course of study in reservoir engineering.
 
James T. Brown joined us in May 1993 as a consulting engineer.  In March 1999, he became Operations Manager, in January 2000, he became Vice President of Operations, and in May 2007, he became Senior Vice President of Operations.  Mr. Brown has over thirty years of oil and gas experience in the Rocky Mountains, Gulf Coast, California and Alaska.  Mr. Brown is a graduate of the University of Wyoming, with a Bachelor’s Degree in civil engineering, and the University of Denver, with an MBA.
 
Bruce R. DeBoer joined us as our Vice President, General Counsel and Corporate Secretary in January 2005.  From January 1997 to May 2004, Mr. DeBoer served as Vice President, General Counsel and Corporate Secretary of Tom Brown, Inc., an independent oil and gas exploration and production company.  Mr. DeBoer has over 20 years of experience in managing the legal departments of several independent oil and gas companies.  He holds a Bachelor of Science Degree in Political Science from South Dakota State University and received his J.D. and MBA degrees from the University of South Dakota.
 
Heather M. Duncan joined us in February 2002 as Assistant Director of Human Resources and in January 2003 became Director of Human Resources.  In January 2008, she was appointed Vice President of Human Resources.  Ms. Duncan has over eleven years of human resources experience in the oil and gas industry.  She holds a Bachelor of Arts Degree in Anthropology and an MBA from the University of Colorado.  She is a certified Professional in Human Resources.
 
 
J. Douglas Lang joined us in December 1999 as Senior Acquisition Engineer and became Manager of Acquisitions and Reservoir Engineering in January 2004 and Vice President—Reservoir Engineering/ Acquisitions in October 2004.  His over thirty years of acquisition and reservoir engineering experience has included staff and managerial positions with Amoco, Petro-Lewis, General Atlantic Resources, UMC Petroleum and Ocean Energy.  Mr. Lang holds a Bachelor’s Degree in Petroleum Engineering from the University of Wyoming and an 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.
 
Rick A. Ross joined us in March 1999 as an Operations Manager.  In May 2007, he became Vice President of Operations.  Mr. Ross has over 25 years of oil and gas experience.  Mr. Ross holds a Bachelor of Science Degree in Mechanical Engineering from the South Dakota School of Mines and Technology.
 
David M. Seery joined us as our Manager of Land in July 2004 as a result of our acquisition of Equity Oil Company, where he was Manager of Land and Manager of Equity’s Exploration Department, positions he had held for more than five years.  He became our Vice President of Land in January 2005.  Mr. Seery has twenty-five years of land experience including staff and managerial positions with Marathon Oil Company.  Mr. Seery holds a Bachelor of Science Degree in Business Management from the University of Montana.  He is a Registered Land Professional and held various duties with the Denver Association of Petroleum Landmen.
 
Michael J. Stevens joined us in May 2001 as Controller, and became Treasurer in January 2002 and became Vice President and Chief Financial Officer in March 2005.  From 1993 until May 2001, he served in various positions including Chief Financial Officer, Controller, Secretary and Treasurer at Inland Resources Inc., a company engaged in oil and gas exploration and development.  He spent seven years in public accounting with Coopers & Lybrand in Minneapolis, Minnesota.  He is a graduate of Mankato State University of Minnesota and is a Certified Public Accountant.
 
Mark R. Williams joined us in December 1983 as Exploration Geologist, becoming Vice President of Exploration and Development in December 1999.  He has twenty-four years of experience in the oil and gas industry and his areas of primary technical expertise are in sequence stratigraphy, seismic interpretation and petroleum economics.  Mr. Williams is a graduate of the Colorado School of Mines with a Master’s Degree in geology and holds a Bachelor’s Degree in geology from the University of Utah.
 
Brent P. Jensen joined us in August 2005 as Controller, and he became Controller and Treasurer in January 2006.  He was previously with PricewaterhouseCoopers L.L.P. in Houston, Texas, where he held various positions in their oil and gas audit practice since 1994, which included assignments of four years in Moscow, Russia and three years in Milan, Italy.  He has fourteen years of oil and gas accounting experience and is a Certified Public Accountant.  Mr. Jensen holds a Bachelor of Arts degree with an emphasis in accounting and business from the University of California, Los Angeles.
 
Executive officers are elected by, and serve at the discretion of, the Board of Directors.  There are no family relationships between any of our directors or executive officers.
 
 
PART II
 
Item 5.
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
Whiting Petroleum Corporation’s common stock is traded on the New York Stock Exchange under the symbol “WLL.”  The following table shows the high and low sale prices for our common stock for the periods presented.
 
   
High
   
Low
 
Fiscal Year Ended December 31, 2007
           
Fourth Quarter (Ended December 31, 2007)
  $ 59.06     $ 44.09  
Third Quarter (Ended September 30, 2007)
  $ 45.14     $ 35.85  
Second Quarter (Ended June 30, 2007)
  $ 47.50     $ 38.71  
First Quarter (Ended March 31, 2007)
  $ 46.04     $ 35.81  
Fiscal Year Ended December 31, 2006
               
Fourth Quarter (Ended December 31, 2006)
  $ 50.30     $ 35.81  
Third Quarter (Ended September 30, 2006)
  $ 48.10     $ 37.30  
Second Quarter (Ended June 30, 2006)
  $ 46.95     $ 33.70  
First Quarter (Ended March 31, 2006)
  $ 47.25     $ 37.41  

On February 15, 2008, there were 869 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 financial position, cash flows, results of operations, capital requirements and investment opportunities.  In addition, the agreements governing our indebtedness prohibit us from paying dividends.
 
Information relating to compensation plans under which our equity securities are authorized for issuance is set forth in Part III, Item 12 of this Annual Report on Form 10-K.
 
The following information in this Item 5 of this Annual Report on Form 10-K is not deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 of the Securities Exchange Act of 1934, and will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent we specifically incorporate it by reference into such a filing.
 
We completed our initial public offering in November 2003.  Our common stock began trading on the New York Stock Exchange on November 20, 2003.  The following graph compares on a cumulative basis changes since November 20, 2003 in (a) the total stockholder return on our common stock with (b) the total return on the Standard & Poor’s Composite 500 Index and (c) the total return on the Dow Jones US Oil Companies, Secondary Index.  Such changes have been measured by dividing (a) the sum of (i) the amount of dividends for the measurement period, assuming dividend reinvestment, and (ii) the difference between the price per share at the end of and the beginning of the measurement period, by (b) the price per share at the beginning of the measurement period.  The graph assumes $100 was invested on November 20, 2003 in our common stock, the Standard & Poor’s Composite 500 Index and the Dow Jones US Oil Companies, Secondary Index.
 
 
 
   
11/20/03
   
12/31/03
   
12/31/04
   
12/31/05
   
12/31/06
   
12/31/07
 
Whiting Petroleum Corporation
  $ 100     $ 113     $ 186     $ 246     $ 286     $ 354  
Standard & Poor’s Composite 500 Index
    100       108       117       121       137       142  
Dow Jones US Oil Companies, Secondary Index
    100       114       160       263       275       392  
 


Item 6.
Selected Financial Data
 
The consolidated income statement information for the years ended December 31, 2007, 2006 and 2005 and the consolidated balance sheet information at December 31, 2007 and 2006 are derived from our audited financial statements included elsewhere in this report.  The consolidated income statement information for the years ended December 31, 2004 and 2003 and the consolidated balance sheet information at December 31, 2005, 2004 and 2003 are derived from audited financial statements that are not included in this report.  Our historical results include the results from our recent acquisitions beginning on the following dates:  Utah Hingeline, August 29, 2006; Michigan Properties, August 15, 2006; North Ward Estes and Ancillary Properties, October 4, 2005; Postle Properties, August 4, 2005; Limited Partnership Interests, June 23, 2005; Green River Basin, March 31, 2005; Permian Basin, September 23, 2004; Equity Oil Company, July 20, 2004; Colorado and Wyoming, August 13, 2004; Wyoming and Utah, September 30, 2004; Louisiana and Texas, August 16, 2004; Mississippi, November 3, 2004; and additional Permian Basin interest, December 31, 2004.
 
   
Year Ended December 31,
 
   
2007
   
2006
   
2005
   
2004
   
2003
 
   
(dollars in millions, except per share data)
 
Consolidated Income Statement Information:
                             
Revenues and other income:
                             
Oil and natural gas sales
  $ 809.0     $ 773.1     $ 573.2     $ 281.1     $ 175.7  
Loss on oil and natural gas hedging activities
    (21.2 )     (7.5 )     (33.4 )     (4.9 )     (8.7 )
Gain on sale of oil and gas properties
    29.7       12.1             1.0        
Gain on sale of marketable securities
                      4.8        
Interest income and other
    1.2       1.1       0.6       0.1       0.3  
Total revenues and other income
    818.7       778.8       540.4       282.1       167.3  
Costs and expenses:
                                       
Lease operating
    208.9       183.6       111.6       54.2       43.2  
Production taxes
    52.4       47.1       36.1       16.8       10.7  
Depreciation, depletion and amortization
    192.8       162.8       97.6       54.0       41.2  
Exploration and impairment
    37.3       34.5       16.7       6.3       3.2  
General and administrative
    39.0       37.8       30.6       19.2       13.0  
Change in Production Participation Plan liability
    8.6       6.2       9.7       1.7       (0.2 )
Phantom equity plan (1)
                            10.9  
Interest expense
    72.5       73.5       42.0       15.9       9.2  
Total costs and expenses
    611.5       545.5       344.3       168.1       131.2  
Income before income taxes and cumulative change in accounting principle
    207.2       233.3       196.1       114.0       36.1  
Income tax expense
    76.6       76.9       74.2       44.0       13.9  
Income before cumulative change in accounting principle
    130.6       156.4       121.9       70.0       22.2  
Cumulative change in accounting principle (2)
                            (3.9 )
Net income
  $ 130.6     $ 156.4     $ 121.9     $ 70.0     $ 18.3  
Income per common share before cumulative change in accounting principle, basic
  $ -     $ -     $ -     $ -     $ 1.18  
Income per common share before cumulative change in accounting principle, diluted
  $ -     $ -     $ -     $ -     $ 1.18  
Net income per common share, basic
  $ 3.31     $ 4.26     $ 3.89     $ 3.38     $ 0.98  
Net income per common share, diluted
  $ 3.29     $ 4.25     $ 3.88     $ 3.38     $ 0.98  
Other Financial Information:
                                       
Net cash provided by operating activities
  $ 394.0     $ 411.2     $ 330.2     $ 134.1     $ 91.9  
Net cash used in investing activities
  $ 467.0     $ 527.6     $ 1,126.9     $ 524.4     $ 47.6  
Net cash provided by financing activities
  $ 77.3     $ 116.4     $ 805.5     $ 338.4     $ 4.4  
Ratio of earnings to fixed charges (3)
    3.65 x     4.14 x     5.64 x     8.01 x     4.85 x
Capital expenditures
  $ 519.6     $ 552.0     $ 1,126.9     $ 530.6     $ 47.6  
 
 
 
   
As of December 31,
 
   
2007
   
2006
   
2005
   
2004
   
2003
 
   
(dollars in millions)
 
Consolidated Balance Sheet Information:
                                       
Total assets
  $ 2,952.0     $ 2,585.4     $ 2,235.2     $ 1,092.2     $ 536.3  
Total debt
  $ 868.2     $ 995.4     $ 875.1     $ 328.4     $ 188.0  
Stockholders’ equity
  $ 1,490.8     $ 1,186.7     $ 997.9     $ 612.4     $ 259.6  


(1)
The completion of our initial public offering in November 2003 constituted a triggering event under our phantom equity plan, pursuant to which our employees received payments valued at $10.9 million in the form of shares of our common stock.  The phantom equity plan is now terminated.
 
 (2)
In 2003, we adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. This was a one-time charge to net income.
 
(3)
For the purpose of calculating the ratio of earnings to fixed charges, earnings consist of income before income taxes and income from equity investees, plus fixed charges, distributed income from equity investees, and amortization of capitalized interest, less capitalized interest.  Fixed charges consist of interest expensed, interest capitalized, amortized premiums, discounts and capitalized expenses related to indebtedness, and an estimate of interest within rental expense.
 
 
 
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Unless the context otherwise requires, the terms “Whiting,” “we,” “us,” “our” or “ours” when used in this Item refer to Whiting Petroleum Corporation, together with its operating subsidiaries, Whiting Oil and Gas Corporation, Equity Oil Company and Whiting Programs, Inc.  When the context requires, we refer to these entities separately.  This document contains forward-looking statements, which give our current expectations or forecasts of future events.  Please refer to “Forward-Looking Statements” at the end of this Item for an explanation of these types of statements.
 
Overview
 
We are an independent oil and gas company engaged in oil and gas acquisition, development, exploitation, production and exploration activities primarily in the Permian Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the United States.  During 2004 and 2005, we emphasized the acquisition of properties that provided additional volumes to our current production levels as well as upside potential through further development.  During 2006 and 2007, we have focused our drilling activity on the development of these acquired properties, specifically on projects that we believe provide repeatable successes in particular fields.  Our combination of acquisitions and subsequent development allows us to direct our capital resources to what we believe to be the most advantageous investments.
 
While historically we have grown through acquisitions, we are increasingly focused on a balanced exploration and development program while continuing to selectively pursue acquisitions that complement our existing core properties.  We believe that our significant drilling inventory, combined with our operating experience and cost structure, provides us with meaningful organic growth opportunities.  Our growth plan is centered on the following activities:
 
 
pursuing the development of projects that we believe will generate attractive rates of return;
 
maintaining a balanced portfolio of lower risk, long-lived oil and gas properties that provide stable cash flows;
 
seeking property acquisitions that complement our core areas; and
 
allocating an increasing percentage of our capital budget to leasing and testing new areas.

We have historically acquired operated and non-operated properties that meet or exceed our rate of return criteria.  For acquisitions of properties with additional development, exploitation and exploration potential, our focus has been on acquiring operated properties so that we can better control the timing and implementation of capital spending.  In some instances, we have been able to acquire non-operated property interests at attractive rates of return that established a presence in a new area of interest or that have complemented our existing operations.  We intend to continue to acquire both operated and non-operated interests to the extent we believe they meet our return criteria.  In addition, our willingness to acquire non-operated properties in new geographic regions provides us with geophysical and geologic data in some cases that leads to further acquisitions in the same region, whether on an operated or non-operated basis.  We sell properties when we believe that the sale price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own.
 
Our revenue, profitability and future growth rate depend on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy.  Oil and gas prices historically have been volatile and may fluctuate widely in the future.  Sustained periods of low prices for oil or gas could materially and adversely affect our financial position, cash flows, results of operations, access to capital, and the quantities of oil and gas reserves that we can economically produce.
 
 
2007 Highlights and Future Considerations
 
On July 3, 2007, we completed a public offering of our common stock under our existing shelf registration statement, selling 5,425,000 shares of common stock at a price of $40.50 per share, providing net proceeds of $210.4 million, which we used to repay a portion of the debt outstanding under our credit agreement.  The number of shares includes the sale of 425,000 shares pursuant to the exercise of the underwriters’ overallotment option.
 
We continue to have significant development and related infrastructure activity on the Postle and North Ward Estes fields acquired in 2005, which has resulted in reserve and production increases.  During 2007, we incurred $284.9 million of exploration and development expenditures on these two projects.  We expect to incur total future development costs of $625.2 million in the North Ward Estes field and $258.7 million in the Postle field.
 
Our expansion of the CO2 flood at the Postle field, located in Texas County, Oklahoma, is generating positive results.  In December 2007, net production from the field averaged 5.8 MBOE/d.  By the end of January 2008, we were injecting over 120 MMcf/d of CO2 into the Morrow formation, the field’s producing reservoir.
 
In 2007, we initiated our CO2 flood in the North Ward Estes field, located in Ward and Winkler Counties, Texas.  By the end of January 2008, we were injecting approximately 120 MMcf/d of CO2 into the Yates formation, the field’s primary producing reservoir.  We expect an initial response from this CO2 flood during the fourth quarter of 2008.  Net production from North Ward Estes in December 2007 averaged 5.1 MBOE/d.
 
Our Robinson Lake prospect in Mountrail County, North Dakota encompasses 118,348 gross acres (83,033 net acres), on which we plan to drill 30 to 40 operated Middle Bakken wells during 2008.  The Peery State 11-25H, our discovery well on the Robinson Lake prospect, was completed in May 2007 in the Middle Bakken formation, and was producing 0.3 MBOE/d at the end of January 2008.  We completed the Locken 11-22H well in December 2007, which averaged 0.9 MBOE/d during the first 30 days of production.  In January 2008, we completed the Liffrig 11-27H well, which averaged 1.1 MBOE/d during the first 30 days of production.  We are the operators on these three wells and have three drilling rigs and one workover rig working full time at Robinson Lake, with plans to add a fifth rig in March 2008.  By year end 2008, we could have as many as nine drillings rigs working in this prospect.
 
In December 2007, we began construction of a natural gas processing plant that will separate the natural gas liquids from the natural gas produced from Robinson Lake and allow the natural gas to be transported by pipeline to market.  The plant is expected to be operational in the second quarter of 2008.  The initial capacity of the plant will be 3.0 MMcf/d, and is expected to increase to approximately 33 MMcf/d by the end of 2008.
 
Immediately east of the Robinson Lake prospect is the Parshall field, where we have participated in the drilling and completion of 24 wells, 19 of which were drilled in 2007.  The initial 15 wells that produced for 120 days had average flow rates of 0.6 MBOE/d per well.  We expect to participate in the drilling of approximately 50 to 60 wells in the Parshall field during 2008.
 
 
Another developmental area for us is in the Piceance Basin at the Boies Ranch and Jimmy Gulch properties in Rio Blanco County, Colorado.  In the first half of 2007, we drilled and completed three gas producers at Boies Ranch, with each well flowing at an initial rate of 2.3 MMcf/d of gas from the Williams Fork and Iles formations.  At year end 2007, there were six wells awaiting completion operations at Boies Ranch and two being drilled, with drilling operations expected to commence at Jimmy Gulch in the third quarter of 2008.  We plan to have a minimum of two drilling rigs running full time in the Piceance Basin, drilling approximately 24 wells by the end of 2008.
 
We are evaluating and engaged in discussions with respect to the potential sale of economic interests in other non-core properties, although we have not made a decision on whether to do so or the form that any such transaction would take.  Our intention is to monetize the value of some of our predominantly proved developed producing properties with this potential sale.  In November 2007, we filed a registration statement relating to a proposed initial public offering of units of beneficial interest in Whiting USA Trust I.  We plan to contribute a term net profits interest in certain of our oil and natural gas properties in exchange for trust units.  These property interests had estimated reserves of up to 8.2 MMBOE, as of a January 1, 2008 effective date, representing up to 3.3% of our proved reserves as of December 31, 2007, and 11.5%, or 4.6 MBOE/d, of our December 2007 average daily net production.  We intend to use the net proceeds from this offering to repay a portion of the debt outstanding under our credit agreement.  The amount of proceeds ultimately received from this offering, and the timing of the completion of this offering, is subject to a variety of factors, including favorable market conditions.  We cannot provide any assurance, however, that we will be able to complete this offering or any other form of asset sales.
 
Although independent engineers estimated probable and possible reserves relating to certain 2006 and prior year producing property acquisitions, we, consistent with our present acquisition practices, have associated substantially all producing property acquisition costs with proved reserves.  Because of our substantial acquisition activity, our discussion and analysis of our historical financial condition and results of operations for the periods discussed below may not necessarily be comparable with or applicable to our future results of operations.  Our historical results include the results from our recent acquisitions beginning on the following dates: Utah Hingeline, August 29, 2006; Michigan Properties, August 15, 2006; North Ward Estes and Ancillary Properties, October 4, 2005; Postle Properties, August 4, 2005; Limited Partnership Interests, June 23, 2005; and Green River Basin, March 31, 2005.
 
Acquisitions
 
Utah Hingeline.  On August 29, 2006, we acquired a 15% working interest in approximately 170,000 acres of unproved properties in the central Utah Hingeline play for $25.0 million.  No producing properties or proved reserves were associated with this acquisition.  As part of this transaction, the operator agreed to pay 100% of our drilling and completion costs for the first three wells in the project.
 
Michigan Properties.  On August 15, 2006, we acquired 65 producing properties, a gathering line, gas processing plant and 30,437 net acres of leasehold held by production in Michigan.  The purchase price was $26.0 million for estimated proved reserves of 1.4 MMBOE as of the acquisition effective date of May 1, 2006, resulting in a cost of $18.55 per BOE of estimated proved reserves.  Proved developed reserve quantities represented 99% of the total proved reserves acquired.  The average daily production from the properties was 0.6 MBOE/d as of the acquisition effective date.  We operate 85% of the acquired properties.
 
North Ward Estes and Ancillary Properties.  On October 4, 2005, we acquired the operated interest in the North Ward Estes field in Ward and Winkler counties, Texas, and certain smaller fields located in the Permian Basin.  The purchase price was $459.2 million, consisting of $442.0 million in cash and 441,500 shares of our common stock, for estimated proved reserves of 82.1 MMBOE as of the acquisition effective date of July 1, 2005, resulting in a cost of $5.58 per BOE of estimated proved reserves.  Proved developed reserve quantities represented 36% of the total proved reserves acquired.  The average daily production from the properties was 4.6 MBOE/d as of the acquisition effective date.  We funded the cash portion of the purchase price with the net proceeds from a public offering of common stock and a private placement of 7% Senior Subordinated Notes due 2014.
 
 
Postle Properties.  On August 4, 2005, we acquired the operated interest in producing oil and gas fields located in the Oklahoma Panhandle.  The purchase price was $343.0 million for estimated proved reserves of 40.3 MMBOE as of the acquisition effective date of July 1, 2005, resulting in a cost of $8.52 per BOE of estimated proved reserves.  The average daily production from the properties was 4.2 MBOE/d as of the acquisition effective date.  Proved developed reserve quantities represented 57% of the total proved reserves acquired.  We funded the acquisition through borrowings under our credit agreement.
 
Limited Partnership Interests.  On June 23, 2005, we acquired all of the limited partnership interests in three institutional partnerships managed by our wholly-owned subsidiary Whiting Programs, Inc.  The partnership properties were located in Louisiana, Texas, Arkansas, Oklahoma and Wyoming.  The purchase price was $30.5 million for estimated proved reserves of 2.9 MMBOE as of the acquisition effective date of January 1, 2005, resulting in a cost of $10.52 per BOE of estimated proved reserves.  Proved developed reserve quantities represented 99% of the total proved reserves acquired.  The average daily production from the properties was 0.7 MBOE/d as of the acquisition effective date.  We funded the acquisition with cash on hand.
 
Green River Basin.  On March 31, 2005, we acquired operated interests in five producing gas fields in the Green River Basin of Wyoming.  The purchase price was $65.0 million for estimated proved reserves of 8.4 MMBOE as of the acquisition effective date of March 1, 2005, resulting in a cost of $7.74 per BOE of estimated proved reserves.  Proved developed reserve quantities represented 68% of the total proved reserves acquired.  The average daily production from the properties was 1.1 MBOE/d as of the acquisition effective date.  We funded the acquisition though borrowings under our credit agreement and with cash on hand.
 
Divestitures
 
On July 17, 2007, we sold our approximate 50% non-operated working interest in several gas fields located in the LaSalle and Webb Counties of Texas for total cash proceeds of $40.1 million, resulting in a pre-tax gain on sale of $29.7 million.  The divested properties had estimated proved reserves of 2.3 MMBOE as of December 31, 2006, adjusted to the July 1, 2007 divestiture effective date, thereby yielding a sale price of $17.77 per BOE.  The June 2007 average daily net production from these fields was 0.8 MBOE/d.
 
During 2007, we sold our interests in several non-core properties for an aggregate amount of $12.5 million in cash for total estimated proved reserves of 0.6 MMBOE as of the divestitures’ effective dates, or $18.82 per BOE.  No gain or loss was recognized on the sales.  These properties are located in Colorado, Louisiana, Michigan, Montana, New Mexico, North Dakota, Oklahoma, Texas and Wyoming.  The average daily net production from the divested property interests was 0.3 MBOE/d as of the dates of disposition.
 
During 2006, we sold our interests in several non-core properties for an aggregate amount of $24.4 million in cash for total estimated proved reserves of 1.4 MMBOE as of the divestitures’ effective dates.  The divested properties included interests in the Cessford field in Alberta, Canada; Permian Basin of West Texas and New Mexico; and the Ashley Valley field in Uintah County, Utah.  The average net production from the divested property interests was 0.4 MBOE/d as of the dates of disposition, and we recognized a pre-tax gain on sale of $12.1 million related to these divestitures.
 
 
Results of Operations
 
The following table sets forth selected operating data for the periods indicated:
 
   
Year Ended December 31,
 
   
2007
   
2006
   
2005
 
Net production:
                 
Oil (MMbbls)
    9.6       9.8       7.0  
Natural gas (Bcf)
    30.8       32.1       30.3  
Total production (MMBOE)
    14.7       15.2       12.1  
Net sales (in millions):
                       
Oil (1)
  $ 618.5     $ 561.2     $ 360.4  
Natural gas (1)
    190.5       211.9       212.8  
Total oil and natural gas sales
  $ 809.0     $ 773.1     $ 573.2  
Average sales prices:
                       
Oil (per Bbl)
  $ 64.57     $ 57.27     $ 51.26  
Effect of oil hedges on average price (per Bbl)
    (2.21 )     (0.95 )     (2.72 )
Oil net of hedging (per Bbl)
  $ 62.36     $ 56.32     $ 48.54  
Average NYMEX price
  $ 72.30     $ 66.25     $ 56.61  
                         
Natural gas (per Mcf)
  $ 6.19     $ 6.59     $ 7.03  
Effect of natural gas hedges on average price (per Mcf)
    -       0.06       (0.47 )
Natural gas net of hedging (per Mcf)
  $ 6.19     $ 6.65     $ 6.56  
Average NYMEX price
  $ 6.86     $ 7.23     $ 8.64  
Cost and expense (per BOE):
                       
Lease operating expenses
  $ 14.20     $ 12.12     $ 9.24  
Production taxes
  $ 3.56     $ 3.11     $ 2.99  
Depreciation, depletion and amortization expense
  $ 13.11     $ 10.74     $ 8.08  
General and administrative expenses
  $ 2.66     $ 2.49     $ 2.53  
________________
(1)  
Before consideration of hedging transactions.

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
 
Oil and Natural Gas Sales.  Our oil and natural gas sales revenue increased $35.9 million to $809.0 million in 2007 compared to 2006.  Sales are a function of volumes sold and average sales prices.  Our oil sales volumes decreased 2% and our gas sales volumes decreased 4% between periods.  The volume declines resulted in part from property sales, production shut-ins due to delays at third-party refineries, and normal field production decline, which factors were partially offset by production increases from development activities.  Our 2007 and 2006 property divestitures resulted in a decline of approximately 317 MBOE, 48% of which related to natural gas.  Approximately 34 MBOE of production from the Postle field was shut-in or restricted from February 19 through March 8, 2007 due to a fire at a third-party refinery, and approximately 32 MBOE of production from the Boies Ranch field was restricted from July 28 to November 18, 2007 due to repairs at the field’s gas processing plant.  During 2007, we also converted several production wells to injectors at our North Ward Estes field, as the Phase I area of the reservoir was pressured up in preparation for CO2 injection.  Our average price for oil before effects of hedging increased 13% and our average price for natural gas before effects of hedging decreased 6% between periods.
 
 
Loss on Oil and Natural Gas Hedging Activities.  We hedged 53% of our oil volumes during 2007, incurring derivative settlement losses of $21.2 million, and 54% of our oil volumes during 2006, incurring derivative settlement losses of $9.4 million.  We hedged 16% of our gas volumes during 2007, incurring no realized hedging gains or losses, and 59% of our gas volumes during 2006, resulting in derivative settlement gains of $1.9 million.  See Item 7A, “Qualitative and Quantitative Disclosures About Market Risk” for a list of our outstanding oil hedges as of January 1, 2008.
 
Gain on Sale of Properties.  During 2007, we sold our interests in several non-core properties for an aggregate amount of $52.6 million in cash, resulting in a pre-tax gain on sale of $29.7 million.  During 2006, we sold our interests in several non-core properties for an aggregate amount of $24.4 million in cash and recognized a pre-tax gain on sale of $12.1 million.
 
Lease Operating Expenses.  Our 2007 lease operating expenses were $208.9 million, a $25.2 million increase over 2006.  Our lease operating expense as a percentage of oil and gas sales increased from 24% during 2006 to 26% during 2007, and our lease operating expenses per BOE increased from $12.12 during 2006 to $14.20 during 2007.  The increase of 17% on a BOE basis was primarily caused by a high level of workover activity, inflation in the cost of oil field goods and services, and a change in labor billing practices.  Workovers amounted to $17.4 million in 2007, as compared to $8.9 million of workover activity during 2006.  The cost of oil field goods and services increased due to a higher demand in the industry.  In addition, during the fourth quarter of 2006, we revised our labor billing practices to better conform to Council of Petroleum Accountants Societies (“COPAS”) guidelines.  This change in labor billing practices resulted in lower net general and administrative expense and higher amounts of lease operating expense being charged to us and our joint interest owners on properties we operate.
 
Production Taxes.  The production taxes we pay are generally calculated as a percentage of oil and gas sales revenue before the effects of hedging.  We take full advantage of all credits and exemptions allowed in our various taxing jurisdictions.  Our production taxes for 2007 and 2006 were 6.5% and 6.1%, respectively, of oil and gas sales.  The 2007 rate was greater than the 2006 rate due to the change in property mix associated with recent divestitures in low tax jurisdictions and drilling successes in higher tax jurisdictions.
 
Depreciation, Depletion and Amortization.  Depreciation, depletion and amortization expense (“DD&A”) increased $30.0 million to $192.8 million during 2007, as compared to $162.8 million for the same period in 2006.  On a BOE basis, our DD&A rate increased from $10.74 during 2006 to $13.11 in 2007.  The primary factors causing this rate increase were (1) $529.3 million in drilling expenditures incurred during the past 12 months in relation to net oil and gas reserve additions over the same time period, and (2) the significant expenditures necessary to develop proved undeveloped reserves, particularly related to the enhanced oil recovery projects in the Postle and North Ward Estes fields, whereby the development of proved undeveloped reserves does not increase existing quantities of proved reserves.  Under the successful efforts method of accounting, costs to develop proved undeveloped reserves are added into the DD&A rate when incurred.  The components of our DD&A expense were as follows (in thousands):
 
   
Year Ended December 31,
 
   
2007
   
2006
 
Depletion
  $ 186,838     $ 157,868  
Depreciation
    3,123       2,675  
Accretion of asset retirement obligations
    2,850       2,288