correspondence.htm

WHITING PETROLEUM CORPORATION 1700 Broadway, Suite 2300 Denver, CO 80290 June 16, 2010
Mr. H. Roger Schwall Assistant Director Division of Corporation Finance U.S. Securities and Exchange Commission 100 F Street, N.E. Washington, DC 20549-4628

Re:

Whiting Petroleum Corporation

Form 10-K for Fiscal Year Ended December 31, 2009

Filed March 1, 2010

Response Letter dated May 12, 2010

File No. 1-31899

Dear Mr. Schwall:

Set forth below are the responses of Whiting Petroleum Corporation (“Whiting”) to the comments of the Staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”) in the Staff’s letter, dated June 8, 2010 (the “Comment Letter”), with respect to the above-referenced filing. The numbered items set forth below repeat (in bold italics) the comments of the Staff reflected in the Comment Letter, and following such comments are Whiting’s responses (in regular type).

Form 10-K for the Fiscal Year Ended December 31, 2009

Properties

Reserves

Proved Undeveloped Reserves, page 34

Your response to prior comment number one explains that our mathematical calculation and resulting suggestion that it will take 18 years to develop your proved undeveloped reserves (“PUD”) is not accurate because the 5.5 MMBOE converted in 2009 did not include significant volumes converted in 2009 from the PUD category to proved developed reserves related to two enhanced oil recovery CO2 flood projects at the North Ward Estes field and the Postle field. As you appear to have excluded significant conversions of proved undeveloped reserves to proved developed reserves from your disclosure, please tell us how your disclosure complies with Item 1203(b) of Regulation S-K.

Company Response:

In a tertiary recovery project such as a CO2 flood, there is not always a direct correlation between the amount of capital investments made on the enhanced oil recovery (“EOR”) project in a given year and the quantities of EOR proved undeveloped reserves (“PUDs”) that are converted to proved developed reserves in that same year. As a result, at the time of filing of our Form 10-K, we could not tie volumes of EOR PUDs converted to proved developed reserves to capital expenditures. In light of the Staff’s comment, we have now developed tracking processes that we believe will reasonably quantify the EOR project capital expenditures that are incurred during a period in an effort to convert EOR PUDs to proved developed reser ves. We will include disclosure in our future Form 10-K filings on (i) the PUD amounts related to our EOR projects that were converted to proved developed reserves in a given year and (ii) the EOR capital expenditures made in an effort to convert such EOR PUDs to proved developed reserves.

Your response to prior comment two indicates that the entire project at the North Ward Estes field could not be implemented at one time “due to the large size of the CO2 flood” and that the staged development is necessary to “recycle CO2 volumes from one area of the reservoir to the next.” Please clarify in further detail whether the staged development is necessary due to external factors related to the physical operating environment or to internal factors and whether any particular external or internal factors necessarily precludes full field development within five years. As part of your response, please address the project criteria presented in Compliance and Disclosure Interpretation Item 108.01 with attention to lost capital from premature project termination and the consequences of an investment decision to develop only a portion of the field reserves.

Company Response:

Background Regarding North Ward Estes Field CO2 Flood Enhanced Recovery Project

The following discussion clarifies why, due to external factors, the North Ward Estes field (the “Field”) CO2 flood enhanced recovery project (the “Project”) could not be implemented at one time “due to the large size of the CO2 flood” and that the staged development is necessary to “recycle CO2 volumes from one area of the reservoir to the next.” By staged development, we are referring to initiation of water injection followed by CO2 injection in several 640 acre sections of land at a time, which we refer to as phases. The CO2 flood at the Project is referred to within the oil and gas industry as a WAG (water alternating gas) process, in which all flooded portions of the reservoir will receive alternating injection volumes of CO2 and water over time. The injection volumes will be predominately CO2 in the early part of the flood, to contact as much of the reservoir oil as possible, followed by increasing water injection volumes to flush the contacted oil from the reservoir.

The Field is one of the largest fields in the Permian Basin with original oil in place estimates exceeding one billion barrels of oil. Geographically, the Field is over twenty miles long and over three miles wide. CO2 injection is planned for approximately 49 sections, each having 640 acres, of the Field.

At the time of Whiting’s acquisition of the Field in 2005, the reservoir pressure was approximately 100 pounds per square inch (“psi”) due to the lack of continuing water injection in this mature field. Proved reserves at that time were approximately 38% developed with the undeveloped portion primarily assigned to the restoration and expansion of the Field’s CO2 enhanced recovery project. Whiting’s Board of Directors approval to acquire the Field was predicated on initiation and completion of the CO2 flood within a time frame that recognized the necessity of implementing the Project in stages.

Staging of phases is necessary to initiate CO2 injection under miscible conditions (i.e., the reservoir pressure must exceed 1,000 psi). This increase in reservoir pressure is obtained by shutting in the producing wells while injecting the majority of the Field’s produced water into the injection wells on the sections of land in the specific phase being initiated. This massive injection of water, without any corresponding withdrawal from the producing wells, increases the reservoir pressure to the desired pressure of 1,400 psi over a several month period. Approximately 30,000 barrels of the Field’s 120,000 barrels of water produced each day are utilized in current water flood areas, leaving 90,000 barrels per day available for the re-pressurization of the next phase of the CO2 flood expansion. Approximately 16,000 barrels of water per day are injected in each section, so the total available water production from the Field of 90,000 barrels per day can be used to re-pressure about five sections at a given time.

Once the necessary reservoir pressure is achieved, the water injection is terminated, and the CO2 injection commences. Approximately 24 million cubic feet per day of pure CO2 is injected initially in each section. Currently available CO2 injection volumes of 220 million cubic feet per day allow CO2 to be injected in about nine sections at a given time. These nine sections include sections where the CO2 flood was initiated earlier, as well as sections that are part of new expansion areas. The 220 million cubic feet of CO2 of available daily injection volume is comprised of 100 million cubic feet of CO2 purchases and 120 million cubic feet of CO2 separated and recompressed at our gas processing plant at the Project.

Our Project is designed to utilize the available water and CO2 resources set out above to develop the field in an efficient and effective manner. The staged, continuous development plan allows us to work within the contraints of the external factors discussed below, to optimize the use of available resources while maximizing the oil recovery in the field.

External Factors Precluding Full Field Development within Five Years

There are three major external factors precluding full field development of the Project within five years:

As discussed above, approximately 16,000 barrels of water per day are necessary to re-pressure a section of the reservoir in preparation for CO2 injection. If re-pressurization of the entire 49 sections of reservoir were to be undertaken at the same time, 784,000 barrels of water per day would be necessary. This volume exceeds water production from the Field’s own water wells by 664,000 barrels per day, and we believe access to additional volumes of this magnitude would be impossible to obtain. Furthermore, even if such a large volume of water were obtainable, once these significant water volumes were used to re-pressure the reservoir and CO2 injection was initiated, the majority of this water would no longer be used in the Field and would have to be promptly disposed of elsewhere. There are no formations underlying the Field that would be acceptable for disposing of this significant volume of water, and we believe arrangements for off-site disposal of this volume of non-potable salt water would also be impossible to secure.

As discussed above, approximately 24 million cubic feet of CO2 is necessary to initiate the CO2 flood on one section of land. If the CO2 flood was initiated on all 49 sections at one time, 1,176 million cubic feet per day of CO2 injection would be required. CO2 volumes of this magnitude are not currently available in the Permian Basin. Furthermore, CO2 suppliers will only agree to contract for a fairly level schedule of CO2 deliveries over a five to ten year contract term. We executed such a contract in 2006 for a term of eight years with a maximum delivery of 134 million cubic feet of CO2 per day in later years. We continue to search for additional CO2 volumes an d currently have a request for proposal out to the Permian Basin CO2 suppliers. If we are able to contract additional CO2 volumes, then we will use them to accelerate our CO2 flood expansion across the Field.

The significant equipment and manpower we are directing toward the continuing development of North Ward Estes is near the maximum level of manageable and safe operations. We are currently using 27 drilling and workover rigs in the Field. Contractor man hours are approximately 8,800 per week.

Due to the three external factors discussed above, full field development of the Project cannot be completed within five years. Based on the magnitude of the equipment and manpower being applied as well as the capital expended ($669 million as of January 1, 2010), Whiting is diligently and efficiently proceeding with the full field development. Whiting has made progress towards converting the Field’s PUDs to proved developed reserves in each year that it has owned the Field.

Single Development Project under Compliance and Disclosure Interpretation Item 108.01

With respect to Compliance and Disclosure Interpretation Item 108.01, the Project is a single development project. It is important to recognize that the Project is distinctly different than a typical industry drilling program for a large field development, which appears to be the topic addressed in Item 108.01. Although the Project involves the re-drilling and re-working of hundreds of wells in the Field, it also requires the development of an overlying infrastructure that allows for the efficient implementation of the Project over the entire planned flooded area.

As discussed in factor 1. above, the re-pressurization of each phase requires the injection of a very large volume of water. Once CO2 injection is started in that phase, that large volume of water is directed to the next phase scheduled for re-pressurization. To move these volumes throughout the Field, we have constructed a water distribution line running the full length of the Field. Further, produced water separated at each production facility is gathered to a central water treatment plant to be processed and redirected to the area of the Field under water injection.

Likewise, we have constructed field-wide CO2 distribution lines to move the pure CO2 (both the daily purchases and the volumes separated and re-compressed at our gas plant) to the phases of the Field undergoing CO2 injection. The mixture of the hydrocarbon gas and the CO2 gas, produced with the oil from the producing wells in the active CO2 flood areas, is gathered at each production facility and transported back to the gas plant for separation and re-compression.

Our gas processing plant that we built at the Project currently processes approximately 130 million cubic feet of hydrocarbon and CO2 gas per day. The gas plant separates out the hydrocarbon gas for sale, recovers natural gas liquids for sale, and recompresses the CO2 to 1,600 psi for distribution and re-injection into the Field.

The majority of the reservoir is continuous and in communication accross the Field. While the entire Project cannot be initiated at the same time due to the external factors described above, it is important that the Field's development be continuous. The water injection in any individual section also affects adjoining sections, and this offset re-pressurization is lost if the development of the CO2 flood does not progress continuously to adjoining sections. Also, the reservoir pressure in the phases under CO2 flood must be maintained above the minimum miscibility pressure. If the pressure falls below the minimum, the miscibility of the CO2 in the oil is lost and the recovery efficiency of the oil drops significantly. Therefore, any material deviation from our staged, continuous development plan could likely resu lt in a loss of minimum miscibility pressure, which would in turn result in a reduction in recovery efficiency of the oil in the reservoir and would waste natural resources. As a result, the Project also constitutes a single engineering activity due to its required continuous, staged development.

We designed and sized the infrastructure required for the CO2 flood to provide the capacity needed to have the required flexibility to move the various fluids and gases around the Field as the Project expands to additional phases. If the Project was terminated prematurely, much of the infrastructure would not be utilized to its capacity and the capital expended for the excess infrastructure would be lost without an economic return. Further, if the Project was terminated early and the planned CO2 flood area was not fully developed, a significant portion of Whiting’s previously invested capital spent in re-developing the Field and its wells would be lost. In addition, Whiting would be obligated to pay for any contracted CO2 volumes no t taken and would lose the benefit of the CO2 already purchased and injected, which is intended to be recycled during the life of the Field. As a result, Whiting would not achieve the economic return that was the basis for the acquisition of the Field and its subsequent capital expenditures, and a significant portion of the capital previously invested by Whiting would be lost.

The Project has a definite cost estimate, which has been reviewed and approved by Whiting’s management and Board of Directors. As of December 31, 2009, Whiting had spent $669 million on the Project and the cost estimate going forward to fully develop and produce the proved reserves was $794 million. The Project also has a definite time schedule, which we developed in accordance with the limiting external factors discussed above and have executed with minimal deviation from the original development plan.

The Project includes all classification of reserves. In general, the probable and possible reserves are assigned to (i) additional sections of land that are expected to be flooded and (ii) incremental recoverable reserves associated with the application of larger CO2 volumes on proved sections. These probable and possible reserves assigned to the Project will be upgraded to proved at such time that the Field’s development and performance justify the capital commitment.

* * *

In accordance with the Staff’s request, Whiting acknowledges that:

·	the company is responsible for the adequacy and accuracy of the disclosure in the filing;

·	staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filings; and

·	the company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

If the Staff has any questions with respect to the foregoing, please contact the undersigned at (303) 837-4228 or in my absence our Vice President and Chief Financial Officer, Michael J. Stevens, at (303) 390-4285.

		Very truly yours,

		/s/ James J. Volker

		James J. Volker
		Chairman, President and Chief Executive Officer

cc: Mark Wojciechowski

Mark Shannon

Norman Gholson

Mike Karney

Securities and Exchange Commission

Bruce R. DeBoer

J. Douglas Lang

Michael J. Stevens

Whiting Petroleum Corporation

Benjamin F. Garmer, III

John K. Wilson

Foley & Lardner LLP