Exhibit 99.1

LOGO

February 11, 2010

Mr. Lynn
A. Peterson
Kodiak Oil & Gas Corp.
1625 Broadway, Suite 250
Denver, Colorado 80202

Dear
Mr. Peterson:

In
accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2009, to the Kodiak Oil & Gas Corp. (Kodiak) interest in
certain oil and gas properties located in Montana, North Dakota, and Wyoming. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by
Kodiak. The estimates in this report have been prepared in accordance with the definitions and guidelines of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion
of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive ActivitiesOil and Gas. Definitions are presented immediately following this letter.
This report has been prepared for Kodiak's use in filing with the SEC.

We
estimate the net reserves and future net revenue to the Kodiak interest in these properties, as of December 31, 2009, to be:

Net Reserves

Future Net Revenue ($)Category

Oil
(Barrels)

Gas
(MCF)

Total

Present Worth
at 10%Proved Developed Producing


1,170,435


1,454,904


45,758,400


25,842,400Proved Undeveloped


2,646,309


2,393,574


63,370,700


13,220,400Total Proved


3,816,744


3,848,478


109,129,100


39,062,800


The
oil reserves shown include crude oil and condensate. Oil volumes are expressed in barrels that are equivalent to 42 United States gallons. Gas volumes are expressed in thousands of
cubic feet (MCF) at standard temperature and pressure bases.

The
estimates shown in this report are for proved developed producing and proved undeveloped reserves. Our study indicates that there are no proved developed non-producing
reserves for these properties at this time. As requested, probable and possible reserves that exist for these properties have not been included. This report does not include any value that could be
attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves
subcategorization is
based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Future
gross revenue to the Kodiak interest is prior to deducting state production taxes and ad valorem taxes. Future net revenue is after deductions for these taxes, future capital
costs, and operating expenses but before consideration of federal income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth. The
present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

For
the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have
not investigated possible environmental liability related to the properties; therefore, our estimates do not include any

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costs
due to such possible liability. Also, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

Prices
used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for
each month in the period January through December 2009. For oil volumes, the average West Texas Intermediate spot price of $61.08 per barrel is adjusted by lease for quality, transportation fees, and
regional price differentials. For gas volumes, the average Questar Rocky Mountain spot price of $3.02 per MMBTU or the average Northern Ventura spot price of $3.95 per MMBTU, as applicable by
respective areas, is adjusted by lease for energy content, transportation fees, and regional price differentials. When applicable, gas prices have been adjusted to include the value for natural gas
liquids. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $51.81 per
barrel of oil and $3.60 per MCF of gas.

Lease
and well operating costs used in this report are based on operating expense records of Kodiak. These costs include the per-well overhead expenses allowed under joint
operating agreements along with estimates of costs to be incurred at and below the district and field levels. Headquarters general and administrative overhead expenses of Kodiak are included to the
extent that they are covered under joint operating agreements for the operated properties. Lease and well operating costs are held constant throughout the lives of the properties. Capital costs are
included as required for workovers, new development wells, and production equipment. The future capital costs are held constant to the date of expenditure.

We
have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the Kodiak interest. Therefore, our estimates of reserves and
future
revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Kodiak receiving its net revenue interest share of estimated future gross gas production.

The
reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of
engineering and geoscience data, can be estimated with reasonable certainty to be economically producible. If the reserves are recovered, the revenues therefrom and the costs related thereto could be
more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering
such reserves may vary from assumptions made while preparing this report. Estimates of reserves may increase or decrease as a result of future operations, market conditions, or changes in regulations.

For
the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost
information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with generally accepted
petroleum engineering and evaluation principles as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum
Engineers (SPE). We used standard engineering and geoscience methods, or a combination of methods, such as performance analysis, volumetric analysis, and analogy, that we considered to be appropriate
and necessary to establish reserves quantities and reserves categorization that conform to SEC definitions and guidelines. A substantial portion of these reserves are for undeveloped locations and
therefore are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. Our expertise is in petroleum
engineering, geoscience, and petrophysical interpretation, not legal or accounting matters; we are not accountants, attorneys, or landmen. As in all aspects of oil and gas evaluation, there are
uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The
titles to the properties have not been examined by Netherland, Sewell & Associates, Inc. (NSAI), nor has the actual degree or type of interest owned been independently
confirmed. The data used in our estimates were obtained from Kodiak, public data sources, and the nonconfidential files of

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NSAI
and were accepted as accurate. Supporting geoscience, field performance, and work data are on file in our office. The technical persons responsible for preparing the reserves estimates presented
herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves
Information promulgated by the SPE. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties and are not employed on a
contingent basis.

Sincerely,NETHERLAND, SEWELL & ASSOCIATES, INC.Texas Registered Engineering Firm F-002699By:

/s/ C.H. (SCOTT) REES III C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive OfficerBy:

/s/ DAN PAUL SMITH Dan Paul Smith, P.E. 49093
Senior Vice President

By:

/s/ JOHN G. HATTNER John G. Hattner, P.G. 559
Senior Vice PresidentDate Signed: February 11, 2010

Date Signed: February 11, 2010


DPS:AHA

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DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The
following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X
Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers,
(2) the FASB Accounting Standards Codification Topic 932, Extractive ActivitiesOil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1)Acquisition of properties.Costs incurred to purchase, lease or otherwise acquire a property, including
costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees,
legal costs, and other costs incurred in acquiring properties.

(2)Analogous reservoir.Analogous reservoirs, as used in resources assessments, have similar rock and fluid
properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide
concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following
characteristics with the reservoir of interest:



Instruction to paragraph (a)(2):Reservoir properties must, in the aggregate, be no more favorable in the analog than in the
reservoir of
interest.

(3)Bitumen.Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or
semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its
natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4)Condensate.Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir
temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5)Deterministic estimate.The method of estimating reserves or resources is called deterministic when a single
value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

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



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Supplemental definitions from the 2007 Petroleum Resources Management System:Developed Producing ReservesDeveloped Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
Improved recovery reserves are considered producing only after the improved recovery project is in operation.Developed Non-Producing ReservesDeveloped Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from
(1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for
mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or
restored with relatively low expenditure compared to the cost of drilling a new well.


(7)Development costs.Costs incurred to obtain access to proved reserves and to provide facilities for
extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other
costs of development activities, are costs incurred to:



(8)Development project.A development project is the means by which petroleum resources are brought to the
status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several
fields and associated facilities with a common ownership may constitute a development project.

(9)Development well.A well drilled within the proved area of an oil or gas reservoir to the depth of a
stratigraphic horizon known to be productive.

(10)Economically producible.The term economically producible, as it relates to a resource, means a resource
which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil
and gas producing activities as defined in paragraph (a)(16) of this section.

(11)Estimated ultimate recovery (EUR).Estimated ultimate recovery is the sum of reserves remaining as of a
given date and cumulative production as of that date.

(12)Exploration costs.Costs incurred in identifying areas that may warrant examination and in examining
specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.
Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration
costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

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(13)Exploratory well.An exploratory well is a well drilled to find a new field or to find a new reservoir in a
field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a
stratigraphic test well as those items are defined in this section.

(14)Extension well.An extension well is a well drilled to extend the limits of a known reservoir.

(15)Field.An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the
same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or
laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms
"structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays,
areas-of-interest, etc.

(16)Oil and gas producing activities.



Instruction 1 to paragraph (a)(16)(i):The oil and gas production function shall be regarded as ending at a
"terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the
production function as:



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Instruction 2 to paragraph (a)(16)(i):For purposes of this paragraph (a)(16), the termsaleable
hydrocarbonsmeans hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.



(17)Possible reserves.Possible reserves are those additional reserves that are less certain to be recovered
than probable reserves.



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(18)Probable reserves.Probable reserves are those additional reserves that are less certain to be recovered
than proved reserves but which, together with proved reserves, are as likely as not to be recovered.



(19)Probabilistic estimate.The method of estimation of reserves or resources is called probabilistic when the
full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated
probabilities of occurrence.

(20)Production costs.



(21)Proved area.The part of a property to which proved reserves have been specifically attributed.

(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

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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.



(23)Proved properties.Properties with proved reserves.

(24)Reasonable certainty.If deterministic methods are used, reasonable certainty means a high degree of
confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the
estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and
geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25)Reliable technology.Reliable technology is a grouping of one or more technologies (including computational
methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(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

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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 (a)(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).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive ActivitiesOil and Gas:932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:a.

Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)b.

Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise
serves as the producer of those reserves (see paragraph 932-235-50-7).The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3
through 50-11B:a.

Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered
only to the extent provided by contractual arrangements in existence at year-end.b.

Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end
costs and assuming continuation of existing economic conditions. if estimated development expenditures are significant, they shall be presented separately from estimated production costs.c.

Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows
relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas
reserves.d.

Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.e.

Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.f.

Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.


(27)Reservoir.A porous and permeable underground formation containing a natural accumulation of producible oil
and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28)Resources.Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations.
A portion of the resources may be estimated to be recoverable, and another portion

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may
be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29)Service well.A well drilled or completed for the purpose of supporting production in an existing field.
Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for
in-situ combustion.

(30)Stratigraphic test well.A stratigraphic test well is a drilling effort, geologically directed, to obtain
information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests
identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development
type" if drilled in a known area.

(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.



From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):Although several types of projectssuch as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locationsby
their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a
longer time period, and any extension beyond five years should be the exception, and not the rule.Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five
years include, but are not limited to, the following:The company's level of ongoing significant development
activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);The company's historical record at completing development of comparable long-term
projects;The amount of time in which the company has
maintained the leases, or booked the reserves, without significant development activities;The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking
significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); andThe extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal
lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).




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(32)Unproved properties.Properties with no proved reserves.

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