Filed pursuant to Rule 424(b)(3)
Registration Statement No. 333-131716

PROSPECTUS SUPPLEMENT NO. 10

to prospectus dated July 27, 2006, as amended on April 9, 2007

10,250,000 Shares

Common Stock

The following information supplements the prospectus dated July 27, 2006, as amended on April 9, 2007, relating to the offer and sale by the selling stockholders identified in the prospectus of up to 10,250,000 shares of our common stock. This prospectus supplement includes our Current Report on Form 8-K, which was filed with the U.S. Securities and Exchange Commission on October 1, 2007.

The information contained in such report is dated as of the date of such report. This prospectus supplement should be read in conjunction with the prospectus dated July 27, 2006, as amended on April 9, 2007, and prior prospectus supplements, which are to be delivered with this prospectus supplement. This prospectus supplement is qualified by reference to the prospectus except to the extent that the information in this prospectus supplement updates and supersedes the information contained in the prospectus dated July 27, 2006, as amended on April 9, 2007, including any supplements or amendments thereto.

Investing in the shares involves risks and uncertainties. See “Risk Factors” beginning on page 10 of the prospectus dated July 27, 2006, as amended on April 9, 2007, and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2007.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus supplement is October 1, 2007.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): October 1, 2007

GEOMET, INC.

(Exact name of Registrant as specified in its charter)

Delaware	000-52155	76-0662382
(State or other jurisdiction of incorporation or organization)	Commission File Number	(I.R.S. Employer Identification No.)

909 Fannin, Suite 1850

Houston, Texas 77010

(Address of Registrant’s Principal Executive Offices)

(713) 659-3855

(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01 Other Events.

On Friday, September 28, 2007, GeoMet, Inc. announced that it would be a presenter on Monday, October 1, 2007, at the 2007 IPAA Oil and Gas Investment Symposium West Conference in San Francisco, California. In the presentation, GeoMet, Inc. summarizes its track record, operational characteristics, growth position and various financial views. Both the presentation and the live webcast will be available on GeoMet’s website at www.geometinc.com. A copy of the press release announcing the presentation is attached hereto as Exhibit 99.1, and a copy of the slideshow presentation is attached hereto as Exhibit 99.2. GeoMet undertakes no obligation to update, supplement or amend the presentation materials attached as Exhibit 99.2.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits. The following exhibit is furnished as part of this Current Report on Form 8-K:

Exhibit No.	Description
99.1	Press release dated September 28, 2007.
99.2	Slideshow presentation—October 1, 2007.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	GeoMet, Inc.
Date: October 1, 2007	By:	/s/ William C. Rankin
		William C. Rankin
		Executive Vice President, Chief Financial Officer and Secretary

INDEX TO EXHIBITS

Exhibit No.	Description
99.1	Press release dated September 28, 2007.
99.2	Slideshow presentation—October 1, 2007.

Exhibit 99.1

GEOMET, INC. TO PRESENT AT IPAA OGIS SAN FRANSICO CONFERENCE

HOUSTON, September 28, 2007 – GeoMet, Inc. (NASDAQ: GMET) announced today that it will be presenting at the IPAA Oil and Gas Investment Symposium West Conference on Monday, October 1, 2007 at 3:55 p.m., Pacific Time.

The presentation, made by Chairman, President and Chief Executive Officer, Darby Seré and Executive Vice President and Chief Financial Officer, William Rankin will be held at the Palace Hotel in San Francisco, California.

Both the presentation and the live webcast will be available on the Company’s website at www.geometinc.com.

About GeoMet, Inc.

GeoMet, Inc. is an independent energy company engaged in the exploration for and development and production of natural gas from coal seams (“coalbed methane” or “CBM”). Our principal operations and producing properties are located in the Cahaba Basin in Alabama and the Central Appalachian Basin in West Virginia and Virginia. We also control additional coalbed methane and oil and gas development rights, principally in Alabama, British Columbia, Colorado, Louisiana, Virginia, and West Virginia.

For more information, please visit the Company’s web site at www.geometinc.com or contact Steve Smith at (713) 287-2251 or ssmith@geometcbm.com.

IPAA OGIS San Francisco

October 1, 2007

Exhibit 99.2

2

Forward Looking Statements

This

presentation

includes

forward-looking

statements

made

in

reliance

on

the

safe

harbor

provisions

of

the

Private

Securities

Litigation

Reform

Act

of

1995.

Words

such

as

"believes,"

"anticipates,"

"expects,"

"intends,“

"targeted,"

and

similar

expressions,

generally

identify

forward-looking

statements

and

should

be

read

carefully.

These

statements

are

based

on

GeoMet's

current

expectations

and

beliefs

and

are

subject

to

a

number

of

risks,

uncertainties

and

assumptions

that

could

cause

actual

results

to

differ

materially

from

those

described

in

the

forward-looking

statements.

Risks,

uncertainties

and

assumptions

include

(i)

risks

inherent

in

the

exploration

for

and

development

and

production

of

coalbed

methane

and

in

estimating

reserves,

(ii)

the

presence

or

recoverability

of

estimated

reserves,

(iii)

the

ability

to

replace

reserves,

(iv)

unexpected

future

capital

expenditures,

(v)

general

economic

conditions,

(vi)

gas

price

volatility,

(vii)

the

success

of

our

hedging

and

other

risk

management

activities,

(viii)

competition,

(ix)

regulatory

changes,

(x)

the

ability

of

management

to

execute

its

plans

to

meet

its

goals,

(xi)

cost

and

availability

of

transportation

to

get

our

gas

to

market,

and

(xii)

other

factors

discussed

in

GeoMet's

filings

with

the

United

States

Securities

and

Exchange

Commission.

GeoMet

assumes

no

obligation

to

publicly

update

or

revise

any

forward-looking

statements

contained

in

this

presentation,

whether

as

a

result

of

new

information,

future

events,

or

otherwise.

3

Summary

Track Record of Success

Substantial

expertise

and

experience

as

a

developer

and

operator

of

coalbed

methane

properties

since 1985

Developed 5 large scale CBM projects in four separate basins (Black Warrior, Raton, Central

Appalachia and Cahaba Basins)

19 person technical, professional and project management team averages more than 16 years of

CBM experience

Operational Characteristics

Proved reserves of 326 Bcf

at YE 06 (75 % proved developed)

Long lived reserves with low finding and development and unit operating costs

Current net daily gas sales volumes of approximately 20 MMcf

100% operational control

Positioned for Growth

Large inventory of development locations in existing 100% W.I. projects

High potential in new development and exploration opportunities

4

Recent Developments

New Development Projects

Lasher

–

10 miles north of Pond Creek Field, West Virginia

–

Approximately 16,548 net leasehold acres

–

Operator with 100% W.I.

Peace River

–

Near Hudson’s Hope, British Columbia

–

Approximately 50,188 gross leasehold acres

–

Operator with 50% W.I.

New Exploration Prospect

Garden City

–

Chattanooga Shale opportunity in North Central Alabama

–

Approximately 60,000 gross leasehold acres

–

Complementary production characteristics to CBM

–

Significant resource in-place

–

Operator with 100% W.I.

5

Recent Developments

Gurnee Field Production

–

Field not yet responding like a typical CBM project and production has been essentially flat

over the past four quarters

–

High-graded 2007 drilling program

–

Conducting new well-treatment techniques to increase production

–

Similar production difficulties encountered in the early stages of Pond Creek field

development

Pond Creek Gathering Line Right-of-Way Litigation

–

May

23,

2007

–

Virginia

Trial

Court

ruled

in

favor

of

CNX

Gas’

“exclusive

rights

claim”

and

enjoined

us

from

transporting

gas

across

the

PMC

property

unless

we

satisfied

several

restrictive requirements

–

June 20, 2007 –

Virginia Supreme Court vacated the injunctive portion of the order and

removed the restrictive requirements allowing us to move our Pond Creek production through

our gathering line

–

July 30, 2007 –

GeoMet petitioned the Virginia Supreme Court to accept our appeal of the

portion of the order that affirmed CNX Gas’

“exclusive rights claim”

Existing Projects

Existing Development Projects

7

Pond Creek Field (Central Appalachia)

Locator Map

West Virginia, Virginia border

Pennsylvanian Age Pottsville coals

Coal thickness ranges from 10 –

30 feet

High gas content -

> than 500 cubic feet

per ton

34,982 net acres under lease

Operator -

GeoMet –

100% W.I.

Key Facts

CDX

Equitable

Resources

Dickinson

CNX Gas

Lasher

Prospect

Virginia

West Virginia

GeoMet

Operations

Other Operations

GeoMet

Operations

Other Operations

GeoMet Gathering Pipeline

Jewell Ridge Pipeline

ETNG Pipeline

Virginia

West Virginia

Nora

Field

Oakwood

Field

8

Pond Creek Field

Profile

2H 2007 Plan

$12 MM CAPEX

Bring online 19 additional wells

Resolve or advance litigation

Operating Data

Initial gas sales in February 2003

Current net sales of approximately

12.5 MMcf/d

Over 200 wells producing

Reserve & Resource Base

130 Bcf

of Proved Reserves at YE 2006

68% proved developed

14 coreholes

to determine gas in-place

Approximately 287 undrilled

locations (85 PUDS) at YE 06

Proved Undeveloped

Potential Drill Sites

Compressor Sites

Proved Developed

Drilled Coreholes

Well locations

High Pressure Pipelines

9

Pond Creek Field

Daily Sales

Gross Daily Gas Sales

Well Count

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

14,000

15,000

16,000

17,000

18,000

0

25

50

75

100

125

150

175

200

225

250

275

300

325

350

375

400

10

Gurnee Field (Cahaba Basin)

Locator Map

Across anticline from Black Warrior Basin

Pennsylvanian Age Pottsville coals

Average coal thickness 50 feet

43,686 net acres under lease

Operator -

GeoMet –

100% W.I.

GeoMet

Cahaba

Operations

GeoMet

Cahaba

Operations

Black Warrior Methane

El

Paso

Energen

Energen

Constellation

Dominion

Resources

El

Paso

White Oak

Creek

Dominion

Resources

Cahaba

Basin

Black

Warrior

River

Cahaba

River

White Oak

Creek

Black

Warrior

Basin

GeoMet Projects

Water Discharge Pipeline

SONAT Bessemer Calera Pipeline

SONAT Interstate Pipeline

GeoMet

High Pressure Pipeline

CDX Pipeline

Enbridge Pipeline

Other CBM Projects

Alabama

Key Facts

11

Gurnee Field (Cahaba Basin)

Profile

Reserve & Resource Base

193 Bcf

of Proved Reserves at YE 06

78% Proved Developed

33 Coreholes

to determine gas in-place

Approximately 346 undrilled

locations

(74 PUDS) at YE 06

2H 2007 Plan

$10.4 MM CAPEX

Bring online 23 additional wells

Well treatment program

Complete and test 2 wells west of

Cahaba River

Operating Data

Full scale development in March 2005

Current net sales approximately

6.5 MMcf/d

Over 200 wells producing

Water Discharge Pipeline

High Pressure Pipeline

Proved Undeveloped

Potential Drill Sites

Compressor Sites

Drilled Coreholes

Proved Developed

Well locations

Cahaba

River

12

Gurnee Field (Cahaba Basin)

Daily Sales

Gross Daily Gas Sales

Daily Water Production

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

20000

New Development Projects

14

Lasher Project

Locator Map

10 miles north of Pond Creek Field

Operator with 100% W.I.

16,548 net contiguous leasehold acres

Key Facts

Virginia

West Virginia

Pond

Creek

Lasher

Wyoming

County

McDowell

County

Buchanan

County

GeoMet

Operations

Columbia Pipeline

West Virginia

15

Lasher Project

Profile

Drill 2 production wells

Secure agreements for pipeline tie-in

Targeting the Pocahontas

formation of the Pottsville coal

group at depths up to 1,800 feet

4 coreholes

to determine gas

in-place

2 production test wells drilled

Approximately 130 undrilled

locations

Operational salt water disposal

well on property

Firm Capacity on Columbia

KA-20 pipeline which crosses property

-

Salt water disposal well

-

Corehole

-

Well sites

Columbia pipeline

-

Production wells

2H 2007 Development Plan

Profile

16

Peace River Project

Locator Map

Near Hudson’s Hope, British Columbia

50,188 gross acres (25,094 net acres)

Operator with 50% W.I.

Attractive royalty incentive package

–

Expected effective rate < 10%

No severance tax

United States

Mexico

Canada

British

Columbia

Key Facts

17

Peace River Project

Profile

Activity To Date

3 coreholes

to determine gas in-place

7 production test wells

2 water disposal wells

Summary

Cretaceous age Gething

coals

Depth

ranges

from

1,000

–

3,000

ft

Over 400 MMcf/d

of available pipeline

capacity crosses acreage

Access to both U.S. and Canadian

gas markets

2007 –

2008 Development Plan

Complete consultations, permitting and project infrastructure

Drill one or more water disposal wells

Drill up to 25 initial development wells

Net CAPEX up to US$25 MM

?

Hudson's

Hope

-

Production Test Well

-

Corehole

-

Salt Water Disposal Well

Garden City Prospect

19

Garden City Prospect

Locator Map

Tuscaloosa

County

Fayette

County

Walker

County

Jefferson

County

Shelby

County

Bibb

County

Chilton

County

Coosa

County

Talladega

County

St. Clair

County

Blount

County

Cullman

County

Winston

County

Birmingham

(Technical

Headquarters)

Gurnee

Field

Alabama

Garden

City

20

Garden City Prospect

Profile

Activity To Date

4 coreholes

drilled to determine gas in-place and

reservoir properties

2H 2007 Plan

$ 2.7 MM Capex

1 Corehole

3 production test wells

Expand acreage position

Summary

Approximately 60,000 gross leasehold acres

Highly organic gas bearing Chattanooga Shale

Depth ranges from 1,700 to 2,000 feet

Shale thickness ranges from 35 –

90 feet

Multiple gas marketing options

Stratigraphic

Unit

Series

Eocene

Paleocene

Claiborne Group

Wilcox Group

Midway Group

Selma Group

Eutaw Group

Tuscaloosa Group

Pottsville Formation

Parkwood

Formation

Floyd Shale

Upper

Middle

&

Lower

Upper

Lower

Fort Payne Chert

Chattanooga Shale

Unnamed Cherty

Limestone

Undifferentiated

Undifferentiated

Stones River Group

Knox Group

Conasauga

Group

Rome Formation

Upper &

Middle

Lower

Upper

Middle

Lower

Middle

Financial Overview

22

Economic Parameters

(1)

The

cost

of

finding

and

developing

reserves

is

calculated

for

the

three

year

time

period

by

taking

the

sum

of

the

cost

incurred

for

exploration,

development

and

acquisition,

including

future

development

costs

attributable

to

proved

undeveloped

reserves,

adjusted

for

the

change

for

the

period

in

the

balance

of

unevaluated

gas

properties

not

subject

to

amortization

and

dividing

such

amount

by

the

total

proved

reserve

additions

(2)

Reserve additions for the period used to compute finding and development costs have been estimated by independent

petroleum engineers and adjusted for revisions to previous estimates.

(3)

See appendix for calculations of three average finding and development

3

year

average

(excluding

future

development

costs

(2)

)

$0.84

per

Mcf

(3)

3

year

average

(including

future

development

costs

(2)

)

$1.16

per

Mcf

(3)

Low

Finding

&

Development

Costs

(1)

Moderate and declining operating costs

< $2.00 per Mcf

Positive gas price differentials

> $0.10 per Mcf

Other

23

Capitalization ($ in thousands)

Long-Term Bank Debt

80,500

$ 

6/30/07

Stockholders' Equity

Total Capitalization

213,726

294,226

$ 

$

Long Term Bank Debt  / Total Capitalization

27%

Bank Debt per Mcf

(1)

0.25

$     

(1)

Reserves as of December 31, 2006

24

Track Record of Growth

(1)

Adjusted EBITDA is defined as EBITDA before unrealized losses (gains) on derivative contracts, stock-based compensation and accretion of asset retirement obligations.

For reconciliation of Adjusted EBITDA, please refer to the appendix.

(2)

Proved

reserves

and

capital

expenditures

include

White

Oak

Creek

Field

working

interest,

sold

in

2004

(3)

Excludes $27 million for acquisition of producing properties in Pond Creek in 2004

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

2003

2004

2005

2006

1H 2007

Net Daily Sales Volumes

Adjusted EBITDA

(1)

0

50

100

150

200

250

300

350

2003

2004

2005

2006

210

263

326

104

White Oak Creek Field working interest, sold in 2004

0

10

20

30

40

50

60

70

80

90

100

2003

2004

2005

2006

2007 E

59

82

62

36

59

0

5000

10000

15000

20000

25000

2003

2004

2005

2006

1H 2007

7,148

9,860

17,829

22,779

3,246

7,226

12,585

3,560

1,475

6,806

8,701

17,064

19,154

12,919

Proved Reserves

(2)

Capital Expenditures

(2) (3)

25

Natural Gas Production Hedges

(1)

(1)

As of June 30, 2007

(2)

Protection is the difference between the Floor (a bought put) and the Floor Price Phase-out (a sold put). This protection

remains

a

constant

and

fixed

price

enhancement

as

prices

decline

below

the

Floor

Price

Phase-out.

Period

Volume

MMBtu

Cap

Floor

Protection

(2)

July 2007 –

October 2007

984,000

$ 10.50

$ 7.38

$ 1.63

November 2007 –

March 2008

1,216,000

$ 14.80

$ 9.00

$ 3.00

April 2008 –

October 2008

1,712,000

$ 10.50

$ 7.00

$ 2.00

Three Way

Collars

Traditional

Collars

July 2007 –

October 2007

492,000

$ 9.75

$ 7.50

n/a

November 2007 –

March 2008

608,000

$ 11.25

$ 8.25

n/a

Weighted Average Price per MMBtu

Type

26

% Estimated Sales Volumes Hedged

0%

10%

20%

30%

40%

50%

60%

70%

27

Summary

Track Record of Success

Operational Characteristics

Positioned for Growth

Appendix

29

Three Year Average Finding and Development Cost

Costs Incurred

Three Years

Ended 12-31-06

Acquisition Costs -

Proved and Unproved

40,072

$              

Exploration Costs

27,339

Development Costs

158,186

Abandonment Costs

2,058

Increase (decrease) in Unevaluated properties not subject to amortization

(23,330)

Three Year Total

204,325

$            

Change in Future Development Costs

77,945

Total Finding & Development Costs -

Including Estimated Future Development Costs

282,270

$            

Proved Reserve Additions (MMcf)

Revisions to Previous Estimates

17,434

Extensions & Discoveries

193,079

Acquisition

33,599

Three Year Total

244,112

Finding Cost -

Excluding Future Development Costs

0.84

$                   

Finding Cost -

Including Future Development Costs

1.16

$                   

30

Reconciliation of Non-GAAP Measure

Six Months

Ended

June 30,

2007

2006

2005

2004

2003

Net Income (loss)

1,973

$        

17,296

$      

(1,573)

$       

3,836

$        

2,560

$        

Add: Interest expense, net of

interest income and amounts

capitalized

2,111

3,097

3,818

916

138

Add (Deduct): Other expense (income) loss

25

10

21

4

7

Add (Deduct):Expense

(benefit)

for income taxes

1,491

10,880

(993)

2,312

1,651

Add: Depreciation, depletion and

amortization

4,341

7,876

4,867

2,691

2,120

Add: Minority interest

-

23

(442)

584

571

EBITDA

9,940

39,182

5,698

10,343

7,047

Add (Deduct): Unrealized losses

(gains) on derivative contracts

2,713

(16,877)

12,059

(542)

101

Add: Stock based compensation

163

317

-

-

-

Add: Accretion expense

103

157

72

59

-

Adjusted EBITDA

12,919

$      

22,779

$      

17,829

$      

9,860

$        

7,148

$        

December 31,

Twelve Months Ended

For More Information, Please Contact:

J. Darby Seré

Chairman, President & CEO

dsere@geometcbm.com

(713) 287 -

2253

William C. Rankin

Executive Vice President & CFO

brankin@geometcbm.com

(713) 287 -

2257

Stephen M. Smith

Treasurer

ssmith@geometcbm.com

(713) 287 -

2251