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 consolidated 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. Prior to 2006, we generally emphasized the acquisition of properties that increased our production levels and provided upside potential through further development. Since 2006, we have focused primarily on organic drilling activity and on the development of previously acquired properties, specifically on projects that we believe provide the opportunity for repeatable successes and production growth. We believe the combination of acquisitions, subsequent development and organic drilling provides us a broad set of growth alternatives and allows us to direct our capital resources to what we believe to be the most advantageous investments.

As demonstrated by our recent capital expenditure programs, we are increasingly focused on a balance between exploration and development programs and 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 a portion of our capital budget to leasing and exploring prospect areas.

We have historically acquired operated and non-operated properties that 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 sales 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.

Oil and natural gas prices have fallen significantly since their third quarter 2008 levels. For example, the daily average NYMEX oil price was $118.13 per Bbl for the third quarter of 2008, $58.75 per Bbl for the fourth quarter of 2008, and $43.21 per Bbl for the first quarter of 2009. Similarly, daily average NYMEX natural gas prices have declined from $10.27 per Mcf for the third quarter of 2008 to $6.96 per Mcf for the fourth quarter of 2008 and $4.92 for the first quarter of 2009. Lower oil and natural gas prices may not only decrease our revenues, but may also reduce the amount of oil and natural gas that we can produce economically and therefore potentially lower our reserve bookings. A substantial or extended decline in oil or natural gas prices may result in impairments of our proved oil and gas properties and may materially and adversely affect our future business, financial condition, cash flows, 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.

First Quarter 2009 Highlights and Future Considerations

Common Stock Offering. In February 2009, we completed a public offering of our common stock under our existing shelf registration statement, selling 8,450,000 shares of common stock at a price of $29.00 per share and providing net proceeds of $234.9 million after underwriters' fees and offering expenses. We used the net offering proceeds to repay a portion of the debt outstanding under Whiting Oil and Gas' credit agreement, and we plan to use the increased credit availability to fund a portion of the planned capital expenditures in our 2009 capital budget.

Operational Highlights. Our Sanish and Parshall fields in Mountrail County, North Dakota target the Bakken formation. Production in this area was affected by winter weather during the first quarter of 2009, which caused delays in trucking operations and well completion activity. In the Parshall field, net production averaged 5.4 MBOE/d in the first quarter of 2009, a 27% decrease from
7.3 MBOE/d in the fourth quarter of 2008. Net production in the Parshall field increased 70% from a net 3.0 MBOE/d in March 2008 to a net 5.1 MBOE/d in March 2009. Despite these weather issues, first quarter 2009 net production in the Sanish field averaged 8.9 MBOE/d, an 11% increase from 8.0 MBOE/d in the fourth quarter of 2008. Net production in the Sanish field increased 740% from a net
1.2 MBOE/d in March 2008 to a net 9.9 MBOE/d in March 2009.

We continue to have significant development and related infrastructure activity on the Postle and North Ward Estes fields acquired in 2005, which have resulted in reserve and production increases. Our expansion of the CO2 flood at both fields continues to generate positive results. During the first quarter of 2009, we incurred $53.0 million of development expenditures on these two projects.

The Postle field is located in Texas County, Oklahoma. Four of our five producing units are currently under active CO2 enhanced recovery projects. As of April 20, 2009, we were injecting 147 MMcf/d of CO2 in this field. Production from the field has increased 27% from a net 6.2 MBOE/d in March 2008 to a net
7.9 MBOE/d in March 2009. Operations are under way to expand CO2 injection into the northern part of the fourth unit, HMU, and to optimize flood patterns in the existing CO2 floods. These expansion projects include the restoration of shut-in wells and the drilling of new producing and injection wells.

The North Ward Estes field is responding positively to our water and CO2 floods, which we initiated in Phase I during May 2007. In early March 2009, we began Phase II of the project. As of April 20, 2009, we were injecting 170 MMcf/d of CO2 in this field. Production from the field has increased 23% from a net 5.2 MBOE/d in March 2008 to a net 6.4 MBOE/d in March 2009. In this field, we are developing new and reactivated wells for water and CO2 injection and production purposes. Additionally, we plan to install oil, gas and water processing facilities in five phases through 2015, and we estimate that the first three phases will be substantially complete by December 2009.

2009 Capital Budget and Major Development Areas. Our current 2009 capital budget for exploration and development expenditures is $420.6 million, which we expect to fund with net cash provided by our operating activities and a portion of the proceeds from the common stock offering we completed in February 2009. To the extent net cash provided by operating activities or oil and natural gas prices are lower than currently anticipated, we would adjust our capital budget accordingly. If net cash provided by operating activities is higher than currently anticipated, we plan to reduce debt levels. Our 2009 capital budget currently is allocated among our major development areas as indicated in the chart below.

                                              2009 Planned Capital Expenditures
 Development Area                                       (In millions)
 Northern Rockies                            $                             227.9
 Enhanced Oil Recovery Projects (1)                                        122.9
 Central Rockies                                                            26.0
 Permian Basin                                                              13.5
 Exploration and early rig termination (2)                                  30.3
 Total                                       $                             420.6


                                     _________

(1) 2009 planned capital expenditures at our CO2 projects include $36.9 million for purchased CO2 at North Ward Estes and $15.3 million for Postle CO2 purchases.
(2) Comprised primarily of exploration salaries, $6.2 million of early rig termination fees, lease delay rentals and seismic surveys.

Results of Operations

Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008

                                                              Three Months Ended
  Selected Operating Data:                                         March 31,
                                                               2009          2008
  Net production:
  Oil (MMBbls)                                                     3.6          2.6
  Natural gas (Bcf)                                                7.9          6.9
  Total production (MMBOE)                                         4.9          3.7

  Net sales (in millions):
  Oil (1)                                                   $    116.3      $ 232.4
  Natural gas (1)                                                 29.9         54.3
  Total oil and natural gas sales                           $    146.2      $ 286.7

  Average sales prices:
  Oil (per Bbl)                                             $    32.55      $ 89.58
  Effect of oil hedges on average price (per Bbl)                 4.10        (8.83 )
  Oil net of hedging (per Bbl)                              $    36.65      $ 80.75
  Average NYMEX price                                       $    43.21      $ 97.96

  Natural gas (per Mcf)                                     $     3.78      $  7.89
  Effect of natural gas hedges on average price (per Mcf)         0.05            -
  Natural gas net of hedging (per Mcf)                      $     3.83      $  7.89
  Average NYMEX price                                       $     4.92      $  8.03

  Cost and expense (per BOE):
  Lease operating expenses                                  $    12.47      $ 14.89
  Production taxes                                          $     1.95      $  4.73
  Depreciation, depletion and amortization expense          $    20.46      $ 13.50
  General and administrative expenses                       $     1.84      $  3.10

(1) Before consideration of hedging transactions.

Oil and Natural Gas Sales. Our oil and natural gas sales revenue decreased $140.6 million to $146.2 million in the first quarter of 2009 compared to the first quarter of 2008. Sales are a function of volumes sold and average sales prices. Our oil sales volumes increased 38% between periods, while our natural gas sales volumes increased 15%. The oil volume increase resulted primarily from drilling success in the North Dakota Bakken area in addition to increased production at our two large CO2 projects, Postle and North Ward Estes. Oil production from the Bakken increased 940 MBbl compared to the first quarter of 2008, while Postle oil production increased 120 MBbl and North Ward Estes oil production increased 130 MBbl over the same prior year period. These production increases were partially offset by the Whiting USA Trust I (the "Trust") divestiture, which decreased oil production by 205 MBbl, as well as normal field production decline. The gas volume increase between periods was primarily the result of incremental gas production of 1,220 MMcf from the Flat Rock acquisition, which we completed on May 30, 2008, higher production in the Boies Ranch area of 840 MMcf, and new production of 700 MMcf from wells drilled in the Gulf Coast region. These production increases were partially offset by the Trust divestiture, which decreased gas production by 1,015 MMcf, as well as normal field production decline. Offsetting the production increases were decreases in average sales prices. Our average price for oil before effects of hedging decreased 64% between periods, and our average price for natural gas before effects of hedging decreased 52%.

Gain (Loss) on Oil and Natural Gas Hedging Activities. Realized cash settlements on commodity derivatives that we have designated as cash flow hedges are recognized as gain (loss) on oil and natural gas hedging activities. During the first quarter of 2009, we incurred cash settlement gains of $13.5 million on such crude oil hedges. During the first quarter of 2008, we incurred realized cash settlement losses of $22.9 million on crude oil derivatives designated as cash flow hedges. None of our natural gas derivatives were designated as cash flow hedges during the first quarter of 2009 or 2008. Effective April 1, 2009, we elected to de-designate all of our commodity derivative contracts that had been previously designated as cash flow hedges as of March 31, 2009 and have elected to discontinue hedge accounting prospectively. See Item 3, "Qualitative and Quantitative Disclosures About Market Risk" for a list of our outstanding oil and natural gas derivatives as of April 1, 2009.

Amortization of Deferred Gain on Sale. In connection with the sale of 11,677,500 Trust units to the public and related oil and gas property conveyance on April 30, 2008, we recognized a deferred gain on sale of $100.1 million. This deferred gain is amortized to income over the life of the Trust on a units-of-production basis. For the three months ended March 31, 2009, we recognized $4.1 million in income as amortization of deferred gain on sale.

Lease Operating Expenses. Our lease operating expenses during the first quarter of 2009 were $61.0 million, a $5.2 million or 9% increase over the same period in 2008. Our lease operating expenses per BOE decreased from $14.89 during the first quarter of 2008 to $12.47 during the first quarter of 2009. The decrease of 16% on a BOE basis was primarily caused by increased production during the first quarter of 2009, partially offset by a high level of workover activity. Workovers amounted to $14.1 million in the first quarter of 2009, as compared to $3.9 million in the first quarter of 2008. The increase in workover activity primarily relates to our two CO2 projects, which are evolving past the construction and start-up phases and moving into an ongoing maintenance and repair phase that involves a significantly higher number of producing and injection wells.

Production Taxes. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenue before the effects of hedging. We take advantage of all credits and exemptions allowed in our various taxing jurisdictions. Our production taxes for the first quarter of 2009 and 2008 were 6.5% and 6.2%, respectively, of oil and natural gas sales. Our production tax rate for the first quarter of 2009 was greater than the rate for same period in 2008 mainly due to successful wells completed in the North Dakota Bakken area during 2008, which carry an 11.5% production tax rate.

Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization ("DD&A") expense increased $49.5 million as compared to the first quarter of 2008. The components of our DD&A expense were as follows (in thousands):

                                                       Three Months Ended
                                                            March 31,
                                                        2009          2008
         Depletion                                   $   97,005     $ 49,044
         Depreciation                                       831          751
         Accretion of asset retirement obligations        2,198          716
         Total                                       $  100,034     $ 50,511

DD&A increased $49.5 million primarily due to $48.0 million in higher depletion expense between periods. Of this $48.0 million increase in depletion, $15.0 million related to higher oil and gas volumes produced during the first quarter of 2009, while $33.0 million related to our higher depletion rate in 2009. On a BOE basis, our DD&A rate increased by 52% from $13.50 for the first quarter of 2008 to $20.46 for the first quarter of 2009. The primary factors causing this rate increase were (i) $902.4 million in drilling expenditures incurred during the past twelve months, (ii) net oil and natural gas reserve reductions of 11.6 MMBOE during 2008, which were primarily attributable to a 39.0 MMBOE downward revision for lower oil and natural gas prices at December 31, 2008, and (iii) 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.

Exploration and Impairment Costs. Our exploration and impairment costs increased $6.3 million, as compared to the first quarter of 2008. The components of exploration and impairment costs were as follows (in thousands):

                                        Three Months Ended
                                             March 31,
                                         2009          2008
                        Exploration   $   12,633     $  8,412
                        Impairment         4,681        2,572
                        Total         $   17,314     $ 10,984

Exploration costs increased $4.2 million during the first quarter of 2009 as compared to the same period in 2008 primarily due to rig termination fees recognized in the first quarter of 2009, partially offset by a decrease in geological and geophysical ("G&G") activity. Rig termination fees totaled $6.2 million during the first quarter of 2009, while we did not pay any rig termination fees in the first quarter of 2008. G&G costs amounted to $3.3 million during the first quarter of 2009, as compared to $5.1 million during the first quarter of 2008. We did not drill any exploratory dry holes during the first quarter of 2009 or 2008. The impairment charges in the first quarter of 2009 and 2008 were primarily related to the amortization of leasehold costs associated with individually insignificant unproved properties. As of March 31, 2009, the amount of unproved properties being amortized totaled $81.6 million, as compared to $55.0 million as of March 31, 2008.

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

                                                      Three Months Ended
                                                           March 31,
                                                       2009          2008
          General and administrative expenses       $   20,996     $ 21,112
          Reimbursements and allocations               (12,016 )     (9,497 )
          General and administrative expense, net   $    8,980     $ 11,615

General and administrative expense before reimbursements and allocations decreased $0.1 million to $21.0 million during the first quarter of 2009. The largest component of the decrease related to $4.1 million in lower accrued distributions under our Production Participation Plan ("Plan") between periods due to a lower level of Plan net revenues (which have been reduced by lease operating expenses and production taxes pursuant to the Plan formula) resulting from lower oil and natural gas prices during the first quarter of 2009 as compared to the same period of 2008. These lower accrued Plan distributions were partially offset by $2.6 million in additional employee compensation for personnel hired during the past twelve months as well as general pay increases. The increase in reimbursements and allocations in 2009 was caused by higher salary costs. Our general and administrative expenses as a percentage of oil and natural gas sales increased from 4% for the first quarter of 2008 to 6% for the first quarter of 2009. This increase was primarily due to decreased oil and gas sales revenue as a result of lower oil and natural gas prices.

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

                                                            Three Months Ended
                                                                 March 31,
                                                             2009          2008
     Senior Subordinated Notes                            $   10,768     $ 11,080
     Credit Agreement                                          3,213        3,917
     Amortization of debt issue costs and debt discount        1,173        1,217
     Other                                                       450          353
     Capitalized interest                                       (924 )     (1,021 )
     Total interest expense                               $   14,680     $ 15,546

The decrease in interest expense of $0.9 million between periods was mainly due to lower interest rates on borrowings under our credit facility, partially offset by a higher level of debt outstanding under our credit facility during the first quarter of 2009. Our weighted average effective cash interest rate was 4.6% during the first quarter of 2009 compared to 6.6% during the first quarter of 2008. Our weighted average debt outstanding during the first quarter of 2009 was $1,215.8 million versus $901.8 million for the first quarter of 2008. After inclusion of non-cash interest costs for the amortization of debt issue costs, debt discount and the accretion of the tax sharing liability, our weighted average effective all-in interest rate was 5.0% during the first quarter of 2009 compared to 7.1% during the first quarter of 2008.

Change in Production Participation Plan Liability. For the three months ended March 31, 2009, this non-cash expense was $0.4 million, a decrease of $5.8 million as compared to the same period in 2008. This expense represents the change in the vested present value of estimated future payments to be made to participants after 2010 under our Plan. Although payments take place over the life of the Plan's oil and gas properties, which for some properties is over 20 years, we expense the present value of estimated future payments over the Plan's five-year vesting period. This expense in 2009 and 2008 primarily reflected (i) changes to future cash flow estimates stemming from the volatile commodity price environment during the past year, (ii) recent drilling activity and property acquisitions, and (iii) employees' continued vesting in the Plan. The average NYMEX prices used to estimate this liability decreased by $0.82 for crude oil and $0.22 for natural gas for the three months ended March 31, 2009, as compared to increases of $3.23 for crude oil and $0.19 for natural gas over the same period in 2008. Assumptions that are used to calculate this liability are subject to estimation and will vary from year to year based on the current market for oil and gas, discount rates and overall market conditions.

(Gain) Loss on Mark-to-Market Derivatives. During 2008, we entered into commodity derivative contracts that we did not designate as cash flow hedges. Accordingly, these derivative contracts are marked-to-market each quarter with fair value gains and losses recognized immediately in earnings. Cash flow is only impacted to the extent that actual cash settlements under these contracts result in making or receiving a payment from the counterparty, and such cash settlement gains and losses are also recorded immediately to earnings as (gain) loss on mark-to-market derivatives. During the first quarter of 2009, we recognized $0.4 million in unrealized mark-to-market derivative losses and $1.5 million in realized cash settlement gains. We also recognized a loss of $22.9 million for the ineffective portion of changes in fair value on our commodity derivatives designated as cash flow hedges. During the first quarter of 2008, we recognized $2.9 million in unrealized mark-to-market derivative gains on contracts not designated as cash flow hedges.

Income Tax Expense (Benefit). Income tax benefit totaled $26.0 million for the first quarter of 2009, versus $36.5 million of income tax expense for the first quarter of 2008. Our effective income tax rate increased from 36.9% for the first quarter of 2008 to 37.3% for the first quarter of 2009. Our effective income tax rate was higher in 2009 due to tax benefits resulting from changes to state apportionment.

Net Income (Loss). Net income (loss) decreased from $62.3 million in income during the first quarter of 2008 to a $43.8 million loss during the first quarter of 2009. The primary reasons for this decrease include a 55% decrease in oil prices (net of hedging); a 51% decrease in natural gas prices (net of hedging); higher lease operating expenses, DD&A, and exploration and impairment; and unrealized losses on commodity derivatives. These negative factors were partially offset by a 31% increase in equivalent volumes sold; lower production taxes, general and administrative expenses, interest expense, Production Participation Plan expense and income taxes; and amortization of deferred gain on sale during the first quarter of 2009.

Liquidity and Capital Resources

Overview. At March 31, 2009, our debt to total capitalization ratio was 37.1%, we had $7.0 million of cash on hand and $2,019.2 million of stockholders' equity. At December 31, 2008, our debt to total capitalization ratio was 40.7%, we had $9.6 million of cash on hand and $1,808.8 million of stockholders' . . .