Exhibit 99.1

February 10,
2010

Mr. Ronald
T. Barnes
Pinnacle Gas Resources, Inc.
1 East Alger, Suite 206
Sheridan, Wyoming 82801

Dear
Mr. Barnes:

In
accordance with your request, we have estimated the proved, probable, and possible reserves and future revenue, as of December 31, 2009, to the Pinnacle Gas
Resources, Inc. (Pinnacle) interest in certain coalbed methane properties located in the Powder River Basin of Montana and Wyoming and the Green River Basin of Wyoming. It is our understanding
that the proved reserves estimated in this report constitute all of the proved reserves owned by Pinnacle. 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 Pinnacle's use in filing with the SEC.

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

Gas Reserves

Future Net Revenue ($)Category

Gross
(MMCF)

Net
(MMCF)

Total

Present Worth
at 10%Proved Developed Producing


10,081.2


5,047.0


4,894.2


4,172.8Proved Developed Non-Producing


11,970.0


6,233.9


5,379.6


3,102.0Proved Undeveloped


5,893.7


3,672.9


1,343.4


322.1Total Proved


27,944.9


14,953.8


11,617.2


7,596.9Probable Developed


8,638.6


4,029.0


4,024.2


2,009.2Probable Undeveloped


5,283.0


3,021.6


1,301.0


503.0Total Probable


13,921.6


7,050.7


5,325.2


2,512.2Possible Developed


27,994.8


21,186.7


19,837.9


8,254.1Possible Undeveloped


59,326.4


42,328.0


25,437.2


7,597.3Total Possible


87,321.1


63,514.8


45,275.1


15,851.4


Totals may not add because of rounding.


Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The
estimates shown in this report are for proved, probable, and possible reserves. 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 Pinnacle 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.

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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 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.

Gas
prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for
the period January through December 2009. The average CIG Rocky Mountains spot price of $3.035 per MMBTU is adjusted by project area for energy content, transportation fees, compression fees,
gathering fees, and contractual price differentials. Gas prices are held constant throughout the lives of the properties.

Lease
and well operating costs used in this report are based on operating expense records of Pinnacle. For nonoperated properties, 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. As requested, lease and well operating costs for the operated
properties are limited to direct lease- and field-level costs and Pinnacle's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the
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 Pinnacle 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 Pinnacle 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; probable and possible reserves are those additional reserves which are sequentially less
certain to be recovered than proved reserves. 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, seismic data, 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. 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 non-producing zones and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based. Therefore, these
reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. In evaluating the information at
our disposal concerning this report, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geoscience.
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

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used
in our estimates were obtained from Pinnacle, other interest owners, public data sources, and the nonconfidential files of 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 Society of Petroleum Engineers. 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 Officer




By:

/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 10, 2010

Date Signed: February 10, 2010


DWB:SDB

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our
clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and
conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital
document.

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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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(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:



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.



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



(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.



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(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 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.



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(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 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).

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(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 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

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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.



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

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