PRATOR BETT, L.L.C.

PETROLEUM ENGINEERS

712 MAIN STREET, SUITE 1830

HOUSTON, TEXAS 77002

TEL (713) 224-1350

FAX (713) 224-1351

February 24, 2014

GeoMet, Inc.
Attn: Mr. William C. Rankin
909 Fannin, Suite 1850
Houston, Texas 77010	Re:	Estimated Reserves and Revenues
		S.E.C. Prices
		Effective December 31, 2013

Gentlemen:

Pursuant to your request, we have estimated the future oil and gas reserves and projected the revenues for certain coal bed methane properties owned by GeoMet, Inc., effective December 31, 2013. The properties evaluated herein are located in Virginia and West Virginia.

Our conclusions, effective December 31, 2013, are as follows:

	Proved
	Developed	Total
S.E.C. Prices	Producing	Proved

Estimated Future Net Oil/Cond., Mbbl	0.0	0.0
Estimated Future Net Gas, MMcf	101,941.4	101,941.4

Estimated Future Gross Revenue, M$	382,779	382,779
Estimated Future Production Taxes, M$	23,644	23,644
Estimated Future Operating Expenses, M$	202,346	202,346
Estimated Future Capital Costs, M$	6,022	6,022
Estimated Future Net Revenue (FNR), M$	150,767	150,767
Discounted FNR at 10%, M$	66,320	66,320
Discounted FNR at 15%, M$	51,576	51,576

Estimated Net Revenues by Year, M$

2014	12,052	12,052
2015	10,481	10,481
2016	9,174	9,174
Subtotal	31,708	31,708
Thereafter	119,060	119,060
Total	150,767	150,767

Estimated Average Net Production Rate - 2014

Oil/Cond., bbl/d	0	0
Gas, Mcf/d	18,275.0	18,275.0

Totals may not add because of computer rounding.

Report Preparation

Purpose of Report — This report was prepared to provide the management of GeoMet, Inc. a projection of future reserves and revenues, effective December 31, 2013, of certain oil and gas properties for year-end reporting purposes.

Reporting Requirements — Reporting Requirements — Securities and Exchange Commission (SEC) Regulation S-K, Subpart 1200, and Regulation S-X, Rule 4-10, and Financial Accounting Standards Board (FASB) Topic 932 require oil and gas reserve information including the Standardized Measure of Discounted Cash Flows (“Standardized Measure”) to be reported by publicly held companies as supplemental financial data. These regulations and standards provide for estimates of Proved reserves and revenues discounted at 10% using specific product price Indexes, and existing economic conditions, operating methods, and government regulations. Under the current SEC regulations a company may, but is not required to, disclose Probable and Possible reserves for public reporting purposes. Prices were held constant for the lives of the properties. A detailed explanation of the future price is included in the Product Prices Section. Alternate sensitivity pricing cases may also be reported in addition to the constant pricing case.

Standards of Practice — This report complies with the Petroleum Resources Management System (SPE-PRMS) which was prepared by the Society of Petroleum Engineers (SPE) and jointly sponsored by the World Petroleum Congress (WPC), the American Association of Petroleum Geologists (AAPG), and the Society of Petroleum Evaluation Engineers (SPEE). The SPE-PRMS defines Proved reserves as those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. In addition, this report also complies with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information, also prepared by the SPE, which sets standards for reserve estimators and auditors and specifies accepted methods for estimating future reserves.

The estimated reserves and revenues shown herein have been prepared in accordance with all the applicable FASB, SEC, SPE and WPC regulation requirements and definitions.

Cash Flow Projections — The reserve and revenue projections contained herein are on a calendar year basis with the first time period beginning January 1st and ending December 31st.

Property Description

The GeoMet, Inc. properties evaluated herein are located in the central Appalachian region of Virginia and West Virginia. All of the wells produce natural gas from coal seams. The properties have been subdivided into two groups. The first group consists of the vertical wells in the Pond Creek and Lasher fields. The second group consists of the horizontal multi-lateral Z-Pinnate wells that are located in six different project areas.

Product Prices

GeoMet, Inc. requested that the product prices utilized in this report were to be based on the calculated S.E.C. price on December 31, 2013. The price was provided by GeoMet, Inc. The price is based on the past 12-month un-weighted arithmetic average of the first-day-of-the-month price for each month in the period. GeoMet also provided the differentials, shrink and Btu content which were applied on a field by field basis.

Below are the price scenario utilized and the resultant adjusted prices, weighted for all Proved properties:

	S.E.C. Prices	Adjusted Prices
	Gas, $/MMbtu	Gas, $/Mcf

2014	3.67	3.74
2015	3.67	3.74
2016	3.67	3.74
2017	3.67	3.75

Thereafter	3.67	3.76
Average over life	—	3.75

Operating Expenses

The operating expenses provided by GeoMet, Inc. on a field by field basis. The normal operating expenses was divided into a fixed and variable cost; dollars per well per month and dollars per Mcf. The fixed portion of the expenses remains constant throughout the life of the properties. In addition to the normal operating cost, compression and transportation charges were deducted as a variable dollars per Mcf expense for all properties, except for the areas that have firm transportation contract; Crab Orchard, Hillman, Lasher, Pond Creek, and Triangle. The firm transportation charge was deducted for the life of each contract at which time a variable transportation was charged based on the cost calculated in the last year of each contract.

Capital Costs

The only capital cost included in this evaluation is the plugging and abandonment cost for each producing property. These costs were provided by GeoMet, Inc. and were applied at the end of the economic life of each well.

Other Considerations

Additional Costs — Costs were not deducted for depletion, depreciation and/or amortization (a non-cash item), or for potential federal income tax. Costs in excess of revenues for uneconomical leases have not been deducted.

Additional Potential Values — Values were not assigned to non-producing acreage or to acreage held by production, if any, or to the salvage of surface and sub-surface equipment.

Near Term Budgeting — We caution that the projected revenues in the near term are subject to considerable variation from our projections primarily because of the potential variability of future product prices and from possible changes to the future work schedule concerning the timing of the non-producing and undeveloped reserve estimates. However, these potential short-term variations are not expected to have a major impact on the estimate of total Proved reserves.

Context — We specifically advise that any particular reserve estimate for a specific property not be used out of context with the overall report.

Data Sources — Data including historical production, historical cost and ownership were supplied by GeoMet, Inc. We have accepted these data as correct.

Production statistics were obtained from GeoMet, Inc. and were generally updated through December 2013.

We retain in our files plots of production histories for all properties and certain other information that we believe are pertinent. We have not inspected the properties evaluated in this report nor have we conducted independent well tests.

THE REVENUES AND PRESENT WORTH OF FUTURE NET REVENUES ARE NOT REPRESENTED TO BE MARKET VALUES EITHER FOR INDIVIDUAL PROPERTIES OR ON A TOTAL PROPERTY BASIS.

		Respectfully submitted,


		/s/ Thomas G. Bett
	[SEAL]
		Thomas G. Bett, P.E.
		TBPE License No. 63496

		Dated: February 24, 2014

Prator Bett, LLC

Texas Registered Engineering Firm

F-1500

TGB:smb

PROFESSIONAL QUALIFICATIONS OF THOMAS G. BETT

The conclusions in this report are the result of the technical analysis conducted by the personnel at Prator Bett, LLC. Mr. Thomas G. Bett was responsible for the projection of reserves and economic analysis that was prepared for this report.

Mr. Bett is co-founder and President of Prator Bett, LLC which was established in 1999. Prator Bett, LLC is a petroleum engineering consulting company providing reservoir-engineering services to its clients. Prator Bett, LLC is located in downtown Houston, Texas. Prator Bett, LLC specializes in economic evaluations for year-end reporting purposes, establishing the borrowing base for several commercial banks, oil and gas acquisitions and divestitures, estate planning, field studies and budgeting. The managing partners of Prator Bett, LLC, M. Drayton Prator, III and Thomas G. Bett, together have over 60 years of consulting experience.

Prior to Prator Bett, LLC, Mr. Bett worked at the consulting firm of Huddleston & Co, Inc. from 1983 until establishing Prator Bett, LLC in 1999. While at Huddleston & Co, Inc., Mr. Bett went from an entry-level engineer to Vice-President of the company. In addition to the normal consulting work (described below) Mr. Bett managed the internal reserve report for an affiliated company that was valued at over $100 million and represented over 1500 wells at the time. He also helped to train the young entry-level engineers which the firm hired.

Mr. Bett’s experience is quite varied and involves very complex field studies, secondary and tertiary projects, special projects, older established basins and new developing fields. Mr. Bett works with small companies to large companies, several large commercial banks for borrowing base reviews, estates, and individuals. Mr. Bett has provided direct testimony in the Department of Energy Offices of Hearings and Appeals, State of Texas Court and Federal Court. Mr. Bett has provided litigation support for several cases.

Mr. Bett earned a Bachelor of Science degree from Texas A&M University in 1982. He is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

PETROLEUM RESERVE DEFINITIONS

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

RULE 4-10(a) of REGULATION S-X PART 210

The definitions below are excerpts from the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration that was published on January 14, 2009. This document includes additions and revisions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

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).

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

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 the 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.

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

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.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic

methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion.

Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

Securities and Exchange Commission Regulation S-X §210.4-10(a)(17) defines possible oil and gas reserves as follows:

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

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible