Exhibit 99

CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS

February 7, 2020

Ms. Trina Medina

Director – Reservoir Engineering

Whiting Petroleum Corporation

1700 Lincoln Street, Suite 4700

Denver, Colorado 80203

Dear Ms. Medina:

We are submitting our estimates of total proved reserves and forecasts of economics attributable to the interests in certain oil and gas properties located in various states within the United States, and such report has been prepared for Whiting Petroleum Corporation (“Whiting”) based on its request.  The proved reserves estimated by us in this report constitute 100% of Whiting’s total proved reserves.  This report, completed February 7, 2020, was prepared for the purpose of public disclosure by Whiting in filings made with the U.S. Securities and Exchange Commission (“SEC”) in accordance with the disclosure requirements set forth in SEC regulations, and it includes results for an SEC pricing scenario accordingly.  The results of this evaluation are presented in the composite summary below:

The oil reserves include oil and condensate. Oil volumes and natural gas liquids (NGLs) are expressed in standard 42 gallon barrels and shown herein as thousands of barrels (Mbbl). Gas volumes are expressed in millions of standard cubic feet (MMcf) at standard temperature and pressure bases. The discounted cash flow value shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc. (CG&A)

Hydrocarbon Pricing

In accordance with SEC guidelines, hydrocarbon prices used in the preparation of this report have been determined as an unweighted arithmetic average of the first-day-of-the-month price for each month of 2019, unless prices were otherwise defined by contractual arrangements. Accordingly, West Texas Intermediate oil and Henry Hub gas prices of $55.69 per bbl and $2.58 per MMBtu, respectively, were used as of December 31, 2019.  Further adjustments were applied on a lease level basis for oil price differentials, gas price differentials and heating values as furnished by your office and audited by CG&A. Prices were not escalated in the SEC scenario.  The average adjusted prices used in the estimation of proved reserves were $50.89 per bbl of oil, $8.72 per bbl of natural gas liquids (NGL) and $0.31 per mcf of natural gas. 

Capital, Expenses and Taxes

Capital expenditures, lease operating expenses and ad valorem tax values were forecast as estimated by your office after thorough examination by CG&A.  As you explained and CG&A verified, the capital costs were based on the most current estimates, lease operating expenses were based on the analysis of historical actual expenses, and operating overhead is included for non-operated properties. Capital costs and lease operating expenses were held constant in accordance with SEC guidelines. State severance tax rates were applied at current statutory percentages of oil, NGL and gas revenue, incorporating certain severance tax incentives and allowances for limited time periods where allowable in Whiting’s various tax jurisdictions.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 2 and 3 of the Appendix.  The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein.  The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered.  However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

Reserve Estimation Methods

The methods employed in estimating reserves are described on page 1 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.  All reserve estimates involve an assessment of the uncertainty relating to the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends mainly on the amount of the reliable geologic and engineering data available at the time of the estimate and the interpretation of such data, as well as the inherent uncertainties attributable to variations in reservoir and rock quality, offset drainage, mechanical wellbore integrity among others.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  This report addresses only the proved reserves attributable to the properties evaluated herein.

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

Miscellaneous

An on-site field inspection of the properties has not been performed. The mechanical operation or conditions of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc.  Possible environmental liability related to the properties has not been investigated nor considered.  The costs of plugging and abandonment, less proceeds from the salvage value of equipment and/or facilities, have been included where material.

The reserve estimates were based on interpretations of factual data furnished by your office.  Raw production data, lease operating statement data, and ownership interests were also supplied by you and were accepted as furnished. Where possible, CG&A has performed a detailed audit on the data provided, and to some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. We have used all methods and procedures as we considered necessary under the circumstances to prepare the report. We believe that the assumptions, data, methods and procedures were appropriate for the purpose served by this report. 

The professional qualifications of the undersigned, the technical personnel primarily responsible for the preparation of this report, are included as an attachment to this letter.

APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy.  Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

Basic information includes production, pressure, geological and laboratory data.  However, a large variation exists in the quality, quantity and types of information available on individual properties.  Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc.  As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data.  The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production performance.  This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance.  The only information required is production history.  Capacity production can usually be analyzed from graphs of rates versus time or cumulative production.  This procedure is referred to as "decline curve" analysis.  Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components.  Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

Material balance.  This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships.  This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir.  The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids.  Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available.  Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use.  Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric.  This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place.  The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location.  The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods.  These are most commonly newly developed and/or no-pressure depleting reservoirs.  The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir.  Reserve estimates obtained by this method are generally considered to have a low degree of accuracy, but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy.  This method, which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells with similar production profiles facilitates the reliable estimation of future reserves with a relatively high degree of accuracy. The analogy method may also be applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained in this manner are generally considered to have a relatively low degree of accuracy.

Much of the information used in the estimation of reserves is itself arrived at by the use of estimates.  These estimates contain inherent uncertainties and are subject to continuing change as additional information becomes available.  Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.

APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

"(22)Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

   "(i)The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

   "(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

   "(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

   "(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

   "(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

"(6)Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

   “(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

   “(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

"(31)Undeveloped oil and gas reserves.  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

   “(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

   “(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

   “(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

"(26)Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”

CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS

Professional Qualifications of W. Todd Brooker, P.E.

President of Cawley, Gillespie & Associates

Mr. Brooker has been a Petroleum Consultant for Cawley, Gillespie & Associates (CG&A) since 1992, and became President in 2017.  His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures.  Prior to CG&A he worked in Gulf of Mexico drilling and production engineering at Chevron USA.  Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering.  He is a registered professional engineer in Texas, No. 83462, and a member of the Society of Petroleum Engineers (SPE) and of the Society of Petroleum Evaluation Engineers (SPEE).