Edgar Filing: GeoMet, Inc.

Large accelerated filer

Accelerated filer

Non-accelerated filer

x (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q for quarterly period ended September 30, 2010

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2010

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 001-32960

GeoMet, Inc.

(Exact name of registrant as specified in its charter)

Delaware

76-0662382

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification Number)

909 Fannin, Suite 1850

Houston, Texas 77010

(713) 659-3855

(Address of principal executive offices and telephone number, including area code)

N/A

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ¨ Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No

As of November 1, 2010, there were 39,758,484 shares issued and outstanding of GeoMet, Inc.’s common stock, par value $0.001 per share.

TABLE OF CONTENTS


Part I. Financial Information

	Item 1.	Consolidated Financial Statements (Unaudited)	3
		Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009	3
		Consolidated Statements of Operations for the three and nine months ended September 30, 2010 and 2009	4
		Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2010 and 2009	5
		Consolidated Statements of Cash Flows for the nine months ended September 30, 2010 and 2009	6
		Notes to Consolidated Financial Statements (Unaudited)	7

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35

	Item 4.	Controls and Procedures	36

Part II. Other Information

	Item 1.	Legal Proceedings	37

	Item 1A.	Risk Factors	37

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40

	Item 3.	Defaults Upon Senior Securities	40

	Item 4.	[Removed and Reserved]	40

	Item 5.	Other Information	40

	Item 6.	Exhibits	40

Part I. Financial Information

Item 1.

Consolidated Financial Statements (Unaudited)

GEOMET, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

(Unaudited)


	September 30, 2010			December 31, 2009
ASSETS
Current Assets:
Cash and cash equivalents	$	697,814		$	973,720
Accounts receivable, net of allowance of $60,848 and $60,848 at September 30, 2010 and December 31, 2009, respectively		2,150,653			2,909,293
Inventory		1,448,037			2,131,901
Derivative asset – natural gas hedges		9,590,574			2,563,898
Other current assets		1,212,320			475,025

Total current assets		15,099,398			9,053,837

Gas properties—utilizing the full cost method of accounting:
Proved gas properties		470,048,507			461,003,091
Other property and equipment		3,351,255			3,480,202

Total property and equipment		473,399,762			464,483,293
Less accumulated depreciation, depletion, amortization and impairment of gas properties		(370,793,227	)		(365,784,964	)

Property and equipment—net		102,606,535			98,698,329


Other noncurrent assets:
Derivative asset – natural gas hedges		3,498,490			761,192
Deferred income taxes		48,095,153			51,804,971
Other		2,211,260			609,972

Total other noncurrent assets		53,804,903			53,176,135

TOTAL ASSETS	$	171,510,836		$	160,928,301


LIABILITIES, MEZZANINE AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	6,353,212		$	5,169,174
Accrued liabilities		2,147,177			2,808,227
Deferred income taxes		3,783,356			157,256
Derivative liability – interest rate swaps		151,560			724,253
Asset retirement liability		57,324			108,111
Current portion of long-term debt		130,875			121,792

Total current liabilities		12,623,504			9,088,813

Long-term debt		79,885,079			119,996,163
Asset retirement liability		5,271,542			4,862,278
Other long-term accrued liabilities		48,872			73,308
Derivative liability - Series A Convertible Redeemable Preferred Stock		16,881,912			—

TOTAL LIABILITIES		114,710,909			134,020,562


Commitments and contingencies (Note 12)
Mezzanine equity:
Series A Convertible Redeemable Preferred Stock - net of offering costs of $1,211,664; redemption amount $40,000,000; $.01 par value; 7,401,832 shares authorized, 4,000,000 shares were issued and outstanding at September 30, 2010, and no shares were authorized, issued and outstanding at December 31, 2009.		20,620,397			—

Stockholders’ Equity:
Preferred stock, $0.001 par value—2,598,168 shares authorized, none issued at September 30, 2010 and 10,000,000 shares authorized, none issued at December 31, 2009		—			—
Common stock, $0.001 par value—authorized 125,000,000 shares; issued and outstanding 39,758,484 and 39,460,060 at September 30, 2010 and December 31, 2009, respectively		39,758			39,294
Treasury stock—10,432 shares at September 30, 2010 and December 31, 2009		(94,424	)		(94,424	)
Paid-in capital		189,804,080			189,681,816
Accumulated other comprehensive loss		(1,408,704	)		(1,768,521	)
Retained deficit		(151,918,661	)		(160,710,889	)
Less notes receivable		(242,519	)		(239,537	)

Total stockholders’ equity		36,179,530			26,907,739

TOTAL LIABILITIES, MEZZANINE AND STOCKHOLDERS’ EQUITY	$	171,510,836		$	160,928,301

See accompanying Notes to Consolidated Financial Statements (Unaudited)

GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Operations

(Unaudited)


	Three months ended September 30,						Nine months ended September 30,
	2010			2009			2010			2009
Revenues:
Gas sales	$	8,239,345		$	6,393,469		$	25,784,384		$	22,683,888
Operating fees and other		77,121			97,032			222,116			271,966

Total revenues		8,316,466			6,490,501			26,006,500			22,955,854
Expenses:
Lease operating expense		2,877,385			3,195,088			8,797,639			11,112,575
Compression and transportation expense		1,095,803			1,234,764			3,175,642			4,049,729
Production taxes		226,785			248,150			723,053			855,805
Depreciation, depletion and amortization		1,561,142			5,168,938			4,656,745			10,187,376
Impairment of gas properties		—			69,145,938			—			236,440,515
General and administrative		1,206,476			1,852,991			3,999,041			7,006,492
Terminated transaction costs		—			—			1,402,534			—
Realized gains on derivative contracts		(1,824,915	)		(3,169,060	)		(5,495,893	)		(8,626,180	)
Unrealized (gains) losses on natural gas contracts		(5,096,346	)		3,567,270			(9,764,362	)		5,525,502

Total operating expenses		46,330			81,224,079			7,494,399			266,551,814

Operating income (loss)		8,270,136			(74,753,578	)		18,512,101			(243,595,960	)

Other income (expense):
Interest income		8,754			5,514			39,615			21,148
Interest expense		(1,510,299	)		(1,385,846	)		(4,177,935	)		(3,787,293	)
Unrealized gain from change in fair value of derivative liability - Series A Convertible Redeemable Preferred Stock		1,595,670			—			1,595,670			—
Other		(24,474	)		4,579			(41,176	)		12,311

Total other income (expense)		69,651			(1,375,753	)		(2,583,826	)		(3,753,834	)

Income (loss) before income taxes		8,339,787			(76,129,331	)		15,928,275			(247,349,794	)
Income tax (expense) benefit		(3,812,588	)		27,786,346			(7,136,047	)		91,894,809

Net income (loss)	$	4,527,199		$	(48,342,985	)	$	8,792,228		$	(155,454,985	)

Accretion of Series A Convertible Redeemable Preferred Stock		(73,532	)		—			(73,532	)		—
Accrued paid-in-kind dividends for Series A Convertible Redeemable Preferred Stock		(236,111	)		—			(236,111	)		—

Net income (loss) available to common stockholders	$	4,217,556		$	(48,342,985	)	$	8,482,585		$	(155,454,985	)

Earnings (loss) per common share:
Net income (loss) available to common stockholders
Basic	$	0.11		$	(1.24	)	$	0.22		$	(3.98	)

Diluted	$	0.10		$	(1.24	)	$	0.21		$	(3.98	)

Weighted average number of common shares:
Basic		39,321,326			39,139,906			39,241,671			39,063,294

Diluted		45,006,945			39,139,906			41,207,732			39,063,294

See accompanying Notes to Consolidated Financial Statements (Unaudited).

GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income (Loss)

(Unaudited)


	Three months ended September 30,					Nine months ended September 30,
	2010		2009			2010		2009

Net income (loss)	$	4,527,199	$	(48,342,985	)	$	8,792,228	$	(155,454,985	)

Gain on foreign currency translation adjustment, net of tax		199		203,045			6,133		384,309

Gain on interest rate swap, net of tax		70,841		53,044			353,685		84,243


Other comprehensive income (loss)	$	4,598,239	$	(48,086,896	)	$	9,152,046	$	(154,986,433	)

See accompanying Notes to Consolidated Financial Statements (Unaudited).

GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)


	Nine Months Ended September 30,
	2010			2009
Cash flows provided by operating activities:
Net income (loss)	$	8,792,228		$	(155,454,985	)
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation, depletion and amortization		4,656,745			10,187,376
Impairment of gas properties		—			236,440,515
Amortization of debt issuance costs		400,786			147,099
Terminated transaction costs		666,306			—
Deferred income tax expense (benefit)		7,117,297			(91,880,770	)
Unrealized (gains) losses from the change in market value of open derivative contracts		(9,764,362	)		5,525,502
Unrealized gain from change in fair value of derivative liability - Series A Convertible Redeemable Preferred Stock		(1,595,670	)		—
Stock-based compensation		302,362			661,263
Loss on sale of assets		53,040			31,076
Accretion expense		362,633			323,726
Changes in operating assets and liabilities:
Accounts receivable		760,938			3,680,724
Inventory		338,021			(178,396	)
Other current assets		(57,599	)		(93,814	)
Accounts payable		297,905			(2,402,377	)
Other accrued liabilities		(680,216	)		(125,530	)

Net cash provided by operating activities		11,650,414			6,861,409

Cash flows used in investing activities:
Capital expenditures		(7,425,981	)		(11,066,497	)
Proceeds from sale of other property and equipment		58,937			19,165
Other assets		84,197			(65,201	)

Net cash used in investing activities		(7,282,847	)		(11,112,533	)

Cash flows provided by financing activities:
Proceeds from sale of preferred stock		40,000,000			—
Proceeds from exercise of stock options		54,137			—
Proceeds from revolver borrowings		18,250,000			33,150,000
Payments on revolver		(58,250,000	)		(30,150,000	)
Deferred financing costs		(3,941,557	)		—
Deferred financing costs related to terminated transactions		(666,306	)		—
Purchase of treasury stock		—			(613	)
Payments on other debt		(102,001	)		(93,678	)

Net cash (used in) provided by financing activities		(4,655,727	)		2,905,709
Effect of exchange rate changes on cash		12,254			67,201

Decrease in cash and cash equivalents		(275,906	)		(1,278,214	)
Cash and cash equivalents at beginning of period		973,720			2,096,561

Cash and cash equivalents at end of period	$	697,814		$	818,347

Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest expense		(4,374,429	)		(3,798,403	)

Income taxes		—			(25,000	)

Significant noncash investing and financing activities:
Accrued capital expenditures		(1,236,665	)		(485,460	)

Accrued paid-in-kind dividends for Series A Convertible Redeemable Preferred Stock		(236,111	)		—

See accompanying Notes to Consolidated Financial Statements (Unaudited).

GEOMET, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(Unaudited)

Note 1 — Organization and Our Business

GeoMet, Inc. (“GeoMet,” “Company,” “we,” or “our”) (formerly GeoMet Resources, Inc.) was incorporated under the laws of the state of Delaware on November 9, 2000. We are an independent natural gas producer primarily involved in the exploration, development and production of natural gas from coal seams (coalbed methane) and non-conventional shallow gas. Our principal operations and producing properties are located in Alabama, West Virginia and Virginia.

The accompanying unaudited consolidated financial statements include our accounts and those of our wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. The unaudited consolidated financial statements reflect, in the opinion of our management, all adjustments, consisting only of normal and recurring adjustments, necessary to present fairly the financial position as of, and results of operations for, the interim periods presented. These unaudited consolidated financial statements have been prepared in accordance with the guidelines of interim reporting; therefore, they do not include all disclosures required for our year-end audited consolidated financial statements prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Interim period results are not necessarily indicative of results of operations or cash flows for the full year. These unaudited consolidated financial statements included herein should be read in conjunction with the audited consolidated financial statements for the fiscal year ended December 31, 2009 and the accompanying notes included in our Annual Report on Form 10-K, as amended, for the year ended December 31, 2009, which we filed with the Securities and Exchange Commission (the “SEC”).

Note 2 — Recent Pronouncements

In January 2010, the FASB issued Update No. 2010-06—Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements. This Update provides amendments to Subtopic 820-10 that require new disclosures for transfers in and out of Levels 1 and 2. This Update also clarifies existing disclosures for level of disaggregation, as well as valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements. The new disclosures and clarifications of existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009. See additional disclosure provided in Note 6 — Derivative Instruments and Hedging Activities.

Note 3 —Income (Loss) Per Share

Income (Loss) Per Share of Common Stock – Earnings (loss) per share—basic is calculated by dividing net income (loss) available to common stockholders—basic by the weighted average number of shares of common stock outstanding during the period. Earnings (loss) per share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing net income (loss) available to common stockholders—diluted by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Earnings (loss) per share—diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential common shares would have an anti-dilutive effect. A reconciliation of the numerator and denominator is as follows:


	Three months ended September 30,						Nine months ended September 30,
	2010			2009			2010			2009
Net income (loss)	$	4,527,199		$	(48,342,985	)	$	8,792,228		$	(155,454,985	)

Accretion of Series A Convertible Redeemable Preferred Stock		(73,532	)		—			(73,532	)		—
Accrued paid-in-kind dividends for Series A Convertible Redeemable Preferred Stock		(236,111	)		—			(236,111	)		—

Net income (loss) available to common stockholders–basic	$	4,217,556		$	(48,342,985	)	$	8,482,585		$	(155,454,985	)

Accretion of Series A Convertible Redeemable Preferred Stock		73,532			—			73,532			—
Accrued paid-in-kind dividends for Series A Convertible Redeemable Preferred Stock		236,111			—			236,111			—

Net income (loss) available to common stockholders–diluted	$	4,527,199		$	(48,342,985	)	$	8,792,228		$	(155,454,985	)

Earnings (loss) per common share:
Net income (loss) available to common stockholders
Basic	$	0.11		$	(1.24	)	$	0.22		$	(3.98	)

Diluted	$	0.10		$	(1.24	)	$	0.21		$	(3.98	)

Weighted average number of common shares:
Basic		39,321,326			39,139,906			39,241,671			39,063,294

Add potentially dilutive securities:
Series A Convertible Redeemable Preferred Stock (30,769,231 common shares, as converted, at September 14, 2010 and 181,262 common shares, as converted, accrued as dividends through September 30, 2010)		5,685,619			—			1,916,033			—
Stock options and non-vested restricted stock		—			—			50,028			—

Diluted		45,006,945			39,139,906			41,207,732			39,063,294

Earnings (loss) per share—diluted for the three and nine months ended September 30, 2010 excluded the effect of outstanding options to purchase 1,661,626 shares because the strike prices of the options exceeded the average market price of our common stock for the period and would have therefore been anti-dilutive. Earnings (loss) per share—diluted for the three and nine months ended September 30, 2009 excluded the effect of outstanding options to purchase 2,419,283 shares and 318,414 shares of restricted stock because we reported a net loss, which caused the options and shares of restricted stock to be anti-dilutive.

Note 4 — Gas Properties

The method of accounting for gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. We use the full cost method of accounting for gas properties as prescribed by the SEC. Under this method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of our gas properties are capitalized and segregated into United States of America (“U.S.”) and Canadian cost centers. The Canadian cost center was fully impaired in 2009 and remains impaired at September 30, 2010.

Gas properties are depleted using the units-of-production method. The depletion expense is significantly affected by the unamortized historical and future development costs and the estimated proved gas reserves. Depletion for the three months ended September 30, 2010 and 2009 was $0.78 and $2.64 per Mcf, respectively. Depletion for the nine months ended September 30, 2010 and 2009 was $0.78 and $1.71 per Mcf, respectively.

Estimation of proved gas reserves relies on professional judgment and use of factors that cannot be precisely determined. Subsequent proved reserve estimates materially different from those reported would change the depletion expense recognized during future reporting periods. No gains or losses are recognized upon the sale or disposition of gas properties unless the sale or disposition represents a significant quantity of gas reserves, which would have a significant impact on the depreciation, depletion and amortization rate.

Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of estimated future net revenues, using the unweighted arithmetic average of the natural gas price on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions, as allowed by the guidelines of the SEC, discounted at 10% per annum, plus cost of properties not being amortized plus the lower of cost or fair value of unevaluated properties less income tax effects (the “ceiling limitation”). We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. The ceiling test is performed

separately for our U.S. and Canadian cost centers. If capitalized costs (net of accumulated depreciation, depletion and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depletion expense in future periods. Once incurred, a write-down is not reversible at a later date. Subsequent to the adoption of Accounting Standards Codification (“ASC”) 410-20-25, formerly Financial Accounting Standard Board (“FASB”) Statement No. 143, Accounting for Asset Retirement Obligations, the future cash outflows associated with settling asset retirement obligations were not included in the computation of the discounted present value of future net revenues for the purposes of the ceiling test calculation.

No impairments were recorded during the three and nine months ended September 30, 2010.

At September 30, 2009, the carrying value of the Company’s gas properties in the U.S. and Canada exceeded the full cost ceiling limitation by $71.2 million, net of income tax of $44.0 million, based upon a natural gas price of approximately $3.38 per Mcf in effect at that date. However, as allowed by the previous guidelines of the SEC, since natural gas prices increased subsequent to September 30, 2009, a recalculation of the ceiling limitation was performed based upon a natural gas price of approximately $4.43 per Mcf in effect at October 30, 2009, adjusted for location differentials. The result of the recalculation was that the net book value of our full cost pool exceeded the ceiling limitation.

For the three months ended September 30, 2009, impairments recorded to gas properties were:


	United States			Canada		Total
Impairment of gas properties	$	69,100,414		$	45,524	$	69,145,938
Deferred income tax benefit		(26,396,358	)		—		(26,396,358	)

Impairment of gas properties, net of tax	$	42,704,056		$	45,524	$	42,749,580

For the nine months ended September 30, 2009, impairments recorded to gas properties were:


	United States			Canada		Total
Impairment of gas properties	$	234,554,219		$	1,886,296	$	236,440,515
Deferred income tax benefit		(89,599,779	)		—		(89,599,779	)

Impairment of gas properties, net of tax	$	144,954,440		$	1,886,296	$	146,840,736

Note 5 — Asset Retirement Liability

We record an asset retirement obligation (“ARO”) on the Consolidated Balance Sheets (Unaudited) and capitalize the asset retirement costs in gas properties in the period in which the retirement obligation is incurred. The amount of the ARO and the costs capitalized are equal to the estimated future costs to satisfy the obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date we incurred the abandonment obligation using an assumed interest rate. Once the ARO is recorded, it is then accreted to its estimated future value using the same assumed interest rate. The following table details the changes to our asset retirement liability for the nine months ended September 30, 2010:


Current portion of liability at January 1, 2010	$	108,111
Add: Long-term asset retirement liability at January 1, 2010		4,862,278

Asset retirement liability at January 1, 2010		4,970,389
Liabilities incurred		41,512
Estimate revisions		(47,609	)
Liabilities settled		(3,794	)
Accretion		362,633
Foreign currency translation		5,735

Asset retirement liability at September 30, 2010		5,328,866
Less: Current portion of liability		(57,324	)

Long-term asset retirement liability	$	5,271,542

Note 6 — Derivative Instruments and Hedging Activities

three-way collars, traditional collars and swaps. While the use of these hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable price movements. Our price risk management policy strictly prohibits the use of derivatives for speculative positions.

We enter into hedging transactions, generally for forward periods up to two years or more, which increase the probability of achieving our targeted level of cash flows. We generally limit the amount of these hedges during any period to no more than 50% to 70% of the then expected gas production for such future periods. Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Costless collars set both a maximum ceiling (a sold ceiling) and a minimum floor (a bought floor) future price. Three-way costless collars are similar to regular costless collars except that, in order to increase the ceiling price, we agree to limit the amount of the floor price protection (through a sold floor) to a predetermined amount, generally between $2.00 and $3.00 per MMBtu below the bought floor. We have accounted for these transactions using the mark-to-market accounting method. Generally, we incur accounting losses on derivatives during periods where prices are rising and gains during periods where prices are falling which may cause significant fluctuations in our Consolidated Balance Sheets (Unaudited) and Consolidated Statements of Operations (Unaudited).

Commodity Price Risk and Related Hedging Activities

At September 30, 2010, we had the following natural gas collar positions:


Period	Volume (MMBtu)		Sold Ceiling		Bought Floor		Sold Floor		Fair Value
October 2010		124,000	$	6.80	$	5.50	$	3.50	$	206,208
October 2010		124,000	$	6.35	$	5.50		—		206,208
November 2010 through March 2011		604,000	$	7.45	$	6.50		—		1,409,114

		852,000							$	1,821,530

At December 31, 2009, we had the following natural gas collar positions:


Period	Volume (MMBtu)		Sold Ceiling		Bought Floor		Sold Floor		Fair Value
January 2010 through March 2010		540,000	$	11.20	$	9.50	$	7.00	$	1,326,724
January 2010 through March 2010		360,000	$	6.65	$	5.50	$	3.50		65,098
April through October 2010		856,000	$	6.80	$	5.50	$	3.50		172,072
April through October 2010		856,000	$	6.35	$	5.50		—		116,559
November 2010 through March 2011		604,000	$	7.45	$	6.50		—		160,745

		3,216,000							$	1,841,198

At September 30, 2010, we had the following natural gas swap positions:


Period	Volume (MMBtu)		Fixed Price		Fair Value
October 2010		124,000	$	5.70	$	230,387
October 2010		93,000	$	6.30		228,589
November 2010 through March 2011		604,000	$	6.67		1,506,454
November 2010 through March 2011		906,000	$	7.27		2,798,614
April 2011 through October 2011		856,000	$	6.37		1,698,989
April 2011 through October 2011		856,000	$	5.37		844,155
April 2011 through October 2011		856,000	$	5.43		899,443
November 2011 through March 2012		608,000	$	7.12		1,224,339
November 2011 through March 2012		608,000	$	6.12		620,276
April 2012 through October 2012		856,000	$	5.73		665,528
November 2012 through March 2013		604,000	$	6.42		550,760

		6,971,000			$	11,267,534

At December 31, 2009, we had the following natural gas swap positions:


Period	Volume (MMBtu)		Fixed Price		Fair Value
April through October 2010		856,000	$	5.70	$	5,341
April through October 2010		642,000	$	6.30		387,383
November 2010 through March 2011		604,000	$	6.67		61,493


Period	Volume (MMBtu)		Fixed Price		Fair Value
November 2010 through March 2011		906,000	$	7.27		625,564
April 2011 through October 2011		856,000	$	6.37		236,887
November 2011 through March 2012		608,000	$	7.12		166,836

		4,472,000			$	1,483,504

Interest Rate Risks and Related Hedging Activities

When we enter into an interest rate swap, we may designate the derivative as a cash flow hedge, at which time we prepare the documentation required under ASC 815-20-25. Hedges of our interest rate are designated as cash flow hedges based on whether the interest on the underlying debt is converted to a fixed interest rate. Changes in derivative fair values that are designated as cash flow hedges are deferred as other comprehensive income or loss to the extent that they are effective and then recognized in earnings when the hedged transactions occur.

We use fixed rate swaps to limit our exposure to fluctuations in interest rates with the objective of realizing a fixed cash flow stream from these activities. At September 30, 2010, we had the following interest rate swaps:


Description	Effective date		Designated maturity date		Fixed rate (1)			Notional amount		Fair Value
Floating-to-fixed swap		12/14/2007		12/14/2010		3.86	%	$	15,000,000	$	(133,898	)
Floating-to-fixed swap		1/6/2009		1/6/2011		1.38	%	$	5,000,000		(17,662	)

								$	20,000,000	$	(151,560	)

At December 31, 2009, we had the following interest rate swaps:


Description	Effective date		Designated maturity date		Fixed rate (1)			Notional amount		Fair Value
Floating-to-fixed swap		12/14/2007		12/14/2010		3.86	%	$	15,000,000	$	(479,566	)
Floating-to-fixed swap		1/3/2008		1/4/2010		3.95	%	$	10,000,000		(87,493	)
Floating-to-fixed swap		3/25/2008		3/25/2010		2.38	%	$	10,000,000		(50,745	)
Floating-to-fixed swap		5/13/2008		5/13/2010		3.07	%	$	5,000,000		(67,783	)
Floating-to-fixed swap		1/6/2009		1/6/2011		1.38	%	$	5,000,000		(38,278	)

								$	45,000,000	$	(723,865	)

(1)	The floating rate paid by the counterparty is the British Bankers’ Association LIBOR rate.

On September 14, 2010, we de-designated the remaining two interest rate swaps which we had previously designated as cash flow hedges under ASC 815-20-25. The de-designation resulted from entering into the Fourth Amended and Restated Credit Agreement which replaced our Third Amended and Restated Credit Agreement. In the new agreement, the notional and interest rates no longer match, and therefore, these two interest rate swaps are no longer effective hedges under ASC 815-20-25. Prospectively, we will account for the remaining interest rate swaps on a mark-to-market basis which will give rise to both realized and unrealized gains and losses in the Consolidated Statements of Operations (Unaudited). Amounts in accumulated other comprehensive income will be frozen and reclassified into earnings as the forecasted transactions impact earnings.

For the three and nine months ended September 30, 2010 and 2009, we recognized no ineffective portion of our cash flow hedges. We have reviewed the financial strength of our hedge counterparties and believe our credit risk to be minimal. Our hedge counterparties are participants in our revolving credit facility agreement and the collateral for the outstanding borrowings under our revolving credit facility agreement is used as collateral for our hedges. We do not have rights to collateral from our counterparties, nor do we have rights of offset against borrowings under our revolving credit facility agreement.

The application of ASC 820-10-55, formerly SFAS No. 157, Fair Value Measurements, currently applies to our derivative instruments. Under the provisions of ASC 820-10-55, we estimate the fair value of our natural gas hedges and interest rate swaps using the income approach. The income approach uses valuation techniques that convert future cash flows to a single discounted value. ASC 820-10-55 clarifies that a fair value measurement for an asset or liability reflects its nonperformance risk, the risk that the obligation will not be fulfilled. Because nonperformance risk includes our counterparties’ and our credit risk, we have considered the effect of our credit risk on the fair value of the liabilities stated below. This consideration involved discounting our counterparties’ and our liabilities based on the difference between the S&P credit rating of a comparable company to ours and the 13-week Treasury bill rate, both as of the reporting date. The following is a description of the valuation methodologies used for our derivative instruments measured at fair value:

•

Natural Gas Hedges—In order to estimate the fair value of our natural gas hedge positions, a forward natural gas price curve and volatility estimates were compiled from sources that include NYMEX settlements and observed trading activity in the Over-the-Counter (OTC) markets. Pricing estimates for the theoretical market value of hedge positions were developed using analytical models accepted and employed by a broad cross-section of industry participants. To extrapolate future cash flows, discount factors incorporating our counterparties’ and our credit standing are used to discount future cash flows.

•

Interest Rate Swaps—In order to estimate the fair value of our interest rate swaps, we use an interest yield curve based on Money Market rates and Interest Rate swaps, extrapolate a forecast of future interest rates, estimate each future cash flow, derive discount factors to value the fixed and floating rate cash flows of each swap, and then discount to present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting techniques used to establish the theoretical market value of interest bearing securities are based on readily available Money Market rates and Interest Rate swap market data. To extrapolate future cash flows, discount factors incorporating our counterparties’ and our credit standing are used to discount future cash flows.

•

Series A Convertible Redeemable Preferred Stock— Upon issuance, the fair value of an embedded derivative liability attributable to the conversion option of the Series A Convertible Redeemable Preferred Stock was bifurcated on the Consolidated Balance Sheet (Unaudited). The fair value of the liability was determined using an American binomial lattice model, which utilized assumptions including 80% volatility and a 17% discount factor.

We did not have any transfers of assets and liabilities between Level 1 and Level 2 of the fair value measurement hierarchy during the three and nine months ended September 30, 2010. Based on the use of observable market inputs, we have designated these types of instruments designated below as Level 2 for ASC 820-10-55 reporting purposes. The fair value of our Level 2 derivative instruments were as follows:


	Asset Derivatives								Liability Derivatives
	September 30, 2010				December 31, 2009				September 30, 2010				December 31, 2009
	Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value
Level 2 Derivatives designated as hedging instruments under ASC 815-20-25
Interest rate swaps		Derivative asset (current)	$	—		Derivative asset (current)	$	—		Derivative liability (current)	$	—		Derivative liability (current)	$	724,253
Interest rate swaps		Derivative asset (non- current)		—		Derivative asset (non- current)		388		Derivative liability (non- current)		—		Derivative liability (non- current)		—


Total level 2 derivative designated as hedging instruments under ASC 815-20-25			$	—			$	388			$	—			$	724,253

Level 2 Derivatives not designated as hedging instruments under ASC 815-20-25
Interest rate swaps		Derivative asset (current)	$	—		Derivative asset (current)	$	—		Derivative liability (current)	$	151,560		Derivative liability (current)	$	—
Natural gas hedge positions		Derivative asset (current)		9,590,574		Derivative asset (current)		2,563,898		Derivative liability (current)		—		Derivative liability (current)		—
Natural gas hedge positions		Derivative asset (non- current)		3,498,490		Derivative asset (non- current)		760,804		Derivative liability (non- current)		—		Derivative liability (non- current)		—

Total level 2 derivative assets (liabilities) not designated as hedging instruments under ASC 815-20-25			$	13,089,064			$	3,324,702			$	151,560			$	—

We have designated the following instrument as Level 3 for ASC 820-10-55 reporting purposes. The fair value of the derivative instrument was as follows:


	Asset Derivatives								Liability Derivatives
	September 30, 2010				December 31, 2009				September 30, 2010				December 31, 2009
	Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value
Derivative liability - Series A Convertible Redeemable Preferred Stock		Derivative asset (non- current)	$	—		Derivative asset (non- current)	$	—		Derivative liability (non- current)	$	16,881,912		Derivative liability (non- current)	$	—

Total level 3 derivative asset (liability) not designated as hedging instruments under ASC 815-20-25			$	—			$	—			$	16,881,912			$	—

The following (gains) losses on our hedging instruments included in the Consolidated Statements of Operations (Unaudited) for the three and nine months ended September 30, 2010 and 2009 and the Consolidated Statements of Comprehensive Income (Loss) (“OCI”) (Unaudited) for the three and nine months ended September 30, 2010 and 2009 are as follows:


Derivatives	Location of (Gain) or Loss Recognized in Income on Derivative	Amount of (Gain) or Loss Recognized in Income on Derivative
		Three months ended September 30,						Nine months ended September 30,
		2010			2009			2010			2009

Derivatives designated as hedging instruments under ASC 815-20-25
Interest rate swaps	Interest expense	$	142,814		$	310,113		$	546,157		$	778,646

Total (gain) loss		$	142,814		$	310,113		$	546,157		$	778,646


Derivatives not designated as hedging instruments under ASC 815-20-25
Derivative liability - Series A Convertible Redeemable Preferred Stock	Unrealized gain from change in fair value of derivative liability - Series A Convertible Redeemable Preferred Stock	$	(1,595,670	)	$	—		$	(1,595,670	)	$	—
Natural gas collar positions	Realized gains on derivative contracts		(1,824,915	)		(3,169,060	)		(5,495,893	)		(8,626,180	)
Natural gas collar positions	Unrealized (gains) losses from the change in market value of open derivative contracts		(5,096,346	)		3,567,270			(9,764,362	)		5,525,502

Total (gain) loss		$	(8,516,931	)	$	398,210		$	(16,855,925	)	$	(3,100,678	)


	Three months ended September 30,				Nine months ended September 30,
	2010		2009		2010			2009

Derivatives in ASC 815-20-25 Cash Flow Hedging Relationships - Interest Rate Swaps

Location of (Gain) Loss Recognized in OCI on Derivative (Effective Portion)		Interest expense
Amount of (Gain) Loss Recognized in OCI on Derivative (Effective Portion)	$	28,185	$	224,280	$	(26,149	)	$	650,812

Location of (Gain) Loss Reclassified from Accumulated OCI into Income (Effective Portion)		Interest expense
Amount of (Gain) Loss Reclassified from Accumulated OCI into Income (Effective Portion)	$	142,814	$	310,113	$	546,157		$	778,646

Location of (Gain) Loss Recognized in income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)		Interest expense
Amount of (Gain) Loss Recognized in income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	$	—	$	—	$	—		$	—

Accumulated comprehensive loss of $1,408,704 as of September 30, 2010 consists of $1,315,040 in foreign currency translation adjustment and a $93,664 loss on interest rate swaps, net of income tax benefit. Accumulated comprehensive loss of $93,664 as of September 30, 2010 is expected to be realized as interest expense in the Consolidated Statement of Operations (Unaudited) in the periods within the 12 months ended September 30, 2011. Accumulated comprehensive loss of $1,768,521 as of December 31, 2009 consists of $1,321,173 in foreign currency translation adjustments and a $447,348 loss on interest rate swaps, net of income tax benefit.

Note 7 — Terminated Transaction Costs

Terminated transaction costs consist of payments made related to a terminated financing transaction between the Company, NGP Capital Resources Company (“NGPC”) and North Shore Energy, LLC (“North Shore”), an affiliate of Yorktown Energy Partners IV, L.P. (“Yorktown”) (Yorktown is a related party to the Company) and expenses related to a terminated sale of certain gas properties. There were no terminated transaction costs for the three months ended September 30, 2010. The following is a detail of terminated transaction costs and related party amounts for the nine months ended September 30, 2010:


	(Related Party) North Shore		NGPC		Other		Total Payments
Initial backstop fees	$	250,000	$	250,000	$	—	$	500,000
Additional fees upon termination		220,000		350,000		—		570,000
Out-of-pocket expenses		49,187		117,041		—		166,228
Legal fees		—		—		102,252		102,252
Costs associated with potential asset sale		—		—		64,054		64,054


Total payments	$	519,187	$	717,041	$	166,306	$	1,402,534

Note 8 — Long-Term Debt

On September 14, 2010, our Fourth Amended and Restated Credit Agreement (the “Credit Agreement”) with a group of five banks became effective. The Credit Agreement replaced our Third Amended and Restated Credit Agreement and provides for revolving credit borrowings of up to $180 million with an initial borrowing base of $90 million. The borrowing base will be determined as of each June and December with the next determination scheduled to be completed by December 2010. All outstanding borrowings under the Credit Agreement become due and payable on September 14, 2013. The Credit Agreement provides for interest to accrue at a rate calculated, at the Company’s option, at the Adjusted Base Rate plus a margin of 1.75% to 2.25% or the London Interbank Offered Rate (the “LIBOR Rate”) rate plus a margin of 2.75% to 3.25%. Adjusted Base Rate is defined to be the greater of (i) the agent’s base rate or (ii) the federal funds rate plus one half of one percent or (iii) the LIBOR Rate plus a margin of 1.00%). In all cases the applicable margin is dependent on the percentage of borrowing base usage. Under the Credit Agreement we are subject to certain financial covenants requiring maintenance of (i) a minimum Current Ratio, (ii) a maximum Debt Ratio and, (iii) depending on our Debt Ratio, either (a) a minimum Interest Coverage Ratio or (b) a minimum Fixed Charge Ratio. The Current Ratio of consolidated current assets (defined to include amounts available under our borrowing base) to consolidated current liabilities (defined to exclude up to $1.5 million in accrued and unpaid preferred dividends) is not permitted to be less than 1.0 to 1.0 as of the end of any fiscal quarter. The Debt Ratio (defined as funded debt at the end of each fiscal quarter to trailing four quarter consolidated EBITDA) at the end of each fiscal quarter cannot exceed 4.5 to 1.0 through the quarter ending June 30, 2011 and 4.0 to 1.0 thereafter. If our Debt Ratio at the end of each fiscal quarter is above 3.5 to 1.0, then the Fixed Charge Ratio (defined as consolidated EBITDA less capital expenditures to consolidated net cash interest expense for the four preceding quarters) is applicable and cannot be less than 1.25 to 1.0. If our Debt Ratio at the end of each fiscal quarter is 3.5 to 1.0 or less, the Interest Coverage Ratio (defined as consolidated EBITDA to consolidated net cash interest expense plus letter of credit fees accruing during the preceding four quarters) is applicable and cannot be less than 2.75. Consolidated EBITDA is defined as earnings (loss) before deducting net interest expense, income taxes, depreciation, depletion and amortization and also excludes non-recurring charges and other non-cash charges deducted in determining net income (loss), which would include unrealized gains and losses from a change in the market value of open derivative contracts. We are also subject to covenants restricting or prohibiting cash dividends and other restricted payments, transactions with affiliates, incurrence of debt, consolidations and mergers, the level of operating leases, assets sales, investments in other entities, and liens on properties. Cash dividends on our preferred stock are permitted if, following any such cash payment our availability is equal to or greater than 15% of the then current borrowing base and our Debt Ratio is less than 3.5 to 1.0. There are no restrictions associated with the payment of PIK dividends on our preferred stock.

As of November 1, 2010, we had $79.1 million of borrowings outstanding under our revolving credit facility, resulting in a borrowing availability of $10.9 million under our $90.0 million borrowing base. On September 14, 2010, we made a payment of $37.2 million which resulted from the funding of a $40 million rights offering completed on the same day. For the three months ended September 30, 2010 we borrowed $7.8 million and made payments of $44.3 million under the revolving credit facility. For the nine months ended September 30, 2010 we borrowed $18.3 million and made payments of $58.3 million under the revolving credit facility. For the three months ended September 30, 2009 we borrowed $4.60 million and made payments of $6.85 million under the revolving credit facility. For the nine months ended September 30, 2009 we borrowed $33.15 million and made payments of $30.15 million under the revolving credit facility. The rates at September 30, 2010 and December 31, 2009, excluding the effect of our interest rate swaps, were 3.59% and 3.03%, respectively.

For the three months ended September 30, 2010 and 2009, interest on the borrowings averaged 4.06% per annum and 3.29% per annum, respectively. For the nine months ended September 30, 2010 and 2009, interest on the borrowings averaged 3.69% per annum and 3.09% per annum, respectively.

The following is a summary of our long-term debt at September 30, 2010 and December 31, 2009:


	September 30, 2010			December 31, 2009
Borrowings under revolving credit facility	$	79,500,000		$	119,500,000
Note payable to a third party, annual installments of $53,000 through January 2011, interest-bearing at 8.25% annually, unsecured		48,961			94,190
Note payable to an individual, semi-monthly installments of $644, through September 2015, interest-bearing at 12.6% annually, unsecured		96,858			106,825
Salary continuation payable to an individual, semi-monthly installments of $3,958, through December 2015, non-interest-bearing (less amortization discount of $572,074, with an effective rate of 8.25%), unsecured		370,135			416,940

Total debt		80,015,954			120,117,955
Less current maturities included in current liabilities		(130,875	)		(121,792	)

Total long-term debt	$	79,885,079		$	119,996,163

The fair value of long-term debt at September 30, 2010 and December 31, 2009 was estimated to be approximately $74.8 million and $115.8 million, respectively. ASC 820-10-55 clarifies that a fair value measurement for an asset or liability reflects its nonperformance risk, the risk that the obligation will not be fulfilled. Because nonperformance risk includes our credit risk, we have considered the effect of our credit risk on the fair value of the long-term debt. This consideration involved discounting our long-term debt based on the difference between the S&P credit rating of a comparable company to ours and the stated interest rates of the debt instruments included our long-term debt, both at September 30, 2010 and December 31, 2009.

In connection with the Fourth Amended and Restated Credit Agreement that became effective September 14, 2010, we incurred $1.4 million in deferred financing costs. The deferred financing costs will be amortized over the term of the credit agreement. In addition, we expensed $0.1 million related to the Third Amended and Restated Credit Agreement which was replaced at that time. In connection with the Third Amended and Restated Credit Agreement, we incurred $0.3 million in deferred financing costs.

Note 9 — Common Stock

At September 30, 2010 and December 31, 2009, there were 39,758,484 and 39,460,060 shares, respectively, of common stock outstanding, both including 10,432 shares of treasury stock held by the Company. Also included in common stock outstanding at September 30, 2010 and December 31, 2009 were 292,512 and 311,684 shares of restricted stock, respectively.

For the three and nine months ended September 30, 2010, 10,758 and 75,190 shares, respectively, of common stock were issued upon the exercise of stock options granted under our 2006 Long-Term Incentive Plan. No common stock was issued upon the exercise of stock options granted under our 2005 Stock Option Plan. On September 20, 2010, we issued 157,622 shares of common stock to our independent directors, representing 50% of their 2010 annual retainer. Additionally, for the nine months ended September 30, 2009, 66,194 shares of restricted stock were forfeited. For the three months ended September 30, 2009, 1,256 shares of restricted stock were forfeited. On March 24, 2010, 300 shares of common stock were purchased by us from a non-executive employee for the payment of $289 in withholding taxes due on vested shares of restricted stock issued under our 2006 Long-Term Incentive Plan. The shares were not retained as treasury stock as they were immediately cancelled.

For the three and nine months ended September 30, 2009, no common stock was issued upon the exercise of stock options granted under our 2005 Stock Option Plan and our 2006 Long-Term Incentive Plan. On March 23, 2009, we issued 166,668 shares of common stock to our independent directors representing 50% of their 2009 retainer. Additionally, for the three and nine months ended September 30, 2009, 1,256 and 4,624 shares of restricted stock, respectively, were forfeited. On June 15, 2009, 403 shares of common stock were purchased by us from a non-executive employee for the payment of $613 in withholding taxes due on vested shares of restricted stock issued under our 2006 Long-Term Incentive Plan. The shares were not retained as treasury stock as they were immediately cancelled.

Note 10 — Series A Convertible Redeemable Preferred Stock

On September 14, 2010, the Company issued and sold 4,000,000 shares of Series A Convertible Redeemable Preferred Stock (“Preferred Stock”), par value $0.001 per share, at a price of $10.00 per share. After paying transaction fees and expenses in the amount of $2.2 million, the Company used the net proceeds of approximately $37.8 million to reduce outstanding bank debt and for general corporate purposes. The Preferred Stock is our most senior equity security. The Preferred Stock ranks senior to our common stock and junior to all of our existing indebtedness.

Dividends are paid quarterly on the Preferred Stock, including any Preferred Stock issued as paid-in-kind dividends (“PIK dividends”), which in our sole discretion, may be paid in any combination of cash, or, until the fifth anniversary of the closing of the rights offering, in PIK dividends. The applicable annual rate for dividends paid in cash is 8.0% for the first three years and 9.6% thereafter. The applicable annual rate for PIK dividends is 12.5%. All dividends are cumulative and all unpaid dividends compound on a quarterly basis at a 12.5% annual rate. At September 30, 2010, an additional 3,401,832 shares of our Preferred Stock are reserved exclusively for the payment of PIK dividends.

The Preferred Stock is immediately convertible into common stock, at the sole option of the holder, at an initial conversion price of $1.30 per common share (as it may be adjusted from time to time, the “Conversion Price”). The Preferred Stock converts into a number of shares of common stock determined by dividing (i) the sum of (A) $10.00 plus (B) accrued but unpaid dividends by (ii) the Conversion Price. At the current Conversion Price, up to an additional 30,950,854 shares of our common stock would be outstanding immediately after conversion of our Preferred Stock. The Conversion Price and resulting number of shares of common stock issued upon conversion of Preferred Stock is adjusted to reflect stock splits and similar events and is entitled to anti-dilution adjustments for any dividends paid on common stock in cash or in common stock, the issuance of additional equity securities at a price less than the Conversion Price (excluding shares, rights and options subject to certain employee benefit arrangements), and the occurrence of certain material corporate transactions at a per share valuation less than the Conversion Price.

At any time beginning eight years from the date of issuance, the Preferred Stock is redeemable, in whole or in part, at the sole option of the holder. The purchase price per share, payable in cash, will be equal to the sum of the original purchase price and any accrued and unpaid dividends.

We have the option, beginning three years from the date of issuance, to convert the Preferred Stock into our common stock at the then current Conversion Price, subject to certain volume and other limitations. In order for us to exercise this option, the daily volume-weighted average trading price of our common stock must be greater than 225% of the then current Conversion Price for twenty (20) out of the previous thirty (30) trading days.

The holders of the Preferred Stock are entitled to vote on all matters on which the holders of our common stock are entitled to vote. The holders of the Preferred Stock generally vote together with the holders of the common stock as a single class, with the Preferred Stock holders entitled to the number of votes such holders would have on an as-converted basis. Certain actions also require a separate vote of the Preferred Stock.

Upon the occurrence of a liquidation, dissolution or winding up of the Company resulting in a payment or distribution of assets to the holders of any of our capital stock (each such event, a “Liquidation Event”), the holders of the Preferred Stock (including PIK dividends) are entitled to receive, prior and in preference to any payment, or segregation for payment, of any consideration to any holder of any junior security of the Company, an amount in cash equal to the greater of (i) $10.00 per share, plus any accrued but unpaid dividends (in each case adjusted for any stock dividends, splits, combinations or similar events), or (ii) an amount equal to the amount such holders of the Preferred Stock would have received upon the Liquidation Event if they had converted their shares of Preferred Stock into shares of our common stock.

If not converted, the Preferred Stock (including any PIK dividends) is redeemable by us on or at any time after a Liquidation Event. In the absence of a Liquidation Event, if not converted, a holder of Preferred Stock (including any PIK dividends) may cause us to redeem the Preferred Stock held by such holder, in whole or in part, on or after September 14, 2018, upon 30 days prior written notice to us. Upon any redemption of Preferred Stock by us, as of the effective date of the redemption, we will pay to each holder of Preferred Stock, $10.00 per share of Preferred Stock (including any PIK dividends) held plus any accrued but unpaid dividends (in each case adjusted for any stock dividends, splits, combinations or similar events).

During the three and nine months ended September 30, 2010, the Company declared no dividends to the holders of Preferred Stock. However, PIK dividends of $236,111 or $0.059028 per share of Preferred Stock were accrued in the Consolidated Balance Sheet (Unaudited) at September 30, 2010 using the PIK dividend rate of 12.5% for the period of September 14, 2010 through September 30, 2010. $137,046 was accrued to Preferred Stock and $99,065 was accrued to Derivative liability - Series A Convertible Redeemable Preferred Stock on the Consolidated Balance Sheet (Unaudited) at September 30, 2010 because quarterly dividends are cumulative.

The Preferred Stock has been classified within the mezzanine (temporary) equity section of the Consolidated Balance Sheets (Unaudited) because the shares are redeemable at the option of the holder and therefore do not qualify for permanent equity. In addition, we evaluated the conversion feature and have determined that its terms require the holder’s conversion option to be separated and recorded at fair value as a derivative liability on the Consolidated Balance Sheets (Unaudited). Subsequent changes in the fair value of the derivative liability will be recorded as a component of other income and expense in the Consolidated Statements of Operations (Unaudited).

The fair value of the derivative liability attributable to the conversion option was determined using an American binomial lattice model, which utilized assumptions including 80% volatility, a 17% discount factor and an expected term of 6.4 years determined using a Monte Carlo simulation model, and resulted in a fair value of approximately $18.4 million on the date of issuance. The remaining net proceeds of $20.4 million were allocated to Series A Convertible Redeemable Preferred Stock in the Consolidated Balance Sheets (Unaudited) at September 30, 2010. For the three and nine months ended September 30, 2010, the Company recorded approximately $1.6 million to Unrealized gain from change in fair value of derivative liability - Series A Convertible Redeemable Preferred Stock in the Consolidated Statements of Operations (Unaudited) as a result of the change in the fair value of the derivative liability.

The following table details the activity related to the issuance and accretion of the Series A Convertible Redeemable Preferred Stock and the related derivative liability for the nine months ended September 30, 2010:


	Mezzanine Equity - Series A Convertible Redeemable Preferred Stock			Derivative Liability - Series A Convertible Redeemable Preferred Stock			Total Liability & Mezzanine Equity Amounts Related to Series A Convertible Redeemable Preferred Stock

Balance at January 1, 2010	$	—		$	—		$	—
Issuance of Series A Convertible Redeemable Preferred Stock		40,000,000			—			40,000,000
Allocated to derivative liability		(18,378,517	)		18,378,517			—
Issuance costs (1)		(1,211,664	)		—			(1,211,664	)

Net issuance of Series A Convertible Redeemable Preferred Stock		20,409,819			18,378,517			38,788,336
Unrealized gain from change in fair value of derivative liability - Series A Convertible Redeemable Preferred Stock		—			(1,595,670	)		(1,595,670	)
Accretion of Series A Convertible Redeemable Preferred Stock		73,532			—			73,532
PIK Dividend accrual for Series A Convertible Redeemable Preferred Stock		137,046			99,065			236,111

Balance at September 30, 2010	$	20,620,397		$	16,881,912		$	39,097,979

(1)

Issuance costs of $2,241,595 were incurred as part of the issuance of the Series A Convertible Redeemable Preferred Stock. As the Series A Convertible Redeemable Preferred Stock was bifurcated on the Consolidated Balance Sheets (Unaudited) as disclosed in the table above, $1,211,665 of the issuance costs were allocated to Mezzanine Equity - Series A Convertible Redeemable Preferred Stock and $1,029,930 were allocated to Other current assets and Other noncurrent assets to be amortized over the term of the Series A Convertible Redeemable Preferred Stock.

Note 11 — Share-Based Awards

As of September 30, 2010, we have two stock-based award plans authorized, which include our 2005 Stock Option Plan and our 2006 Long-Term Incentive Plan. However, we will not grant any additional awards under our 2005 Stock Option Plan now that we have adopted our 2006 Long-Term Incentive Plan, although we will continue to issue shares of our common stock upon exercise of awards previously granted under the 2005 Stock Option Plan.

Our 2006 Long-Term Incentive Plan authorized the granting of incentive stock options, non-qualified stock options, stock appreciation rights, stock awards, restricted stock, restricted stock units and performance awards. A maximum of 4,000,000 shares is

available for grant under this plan. The 2006 Long-Term Incentive Plan is available to our employees and independent directors and is designed to attract and retain employees and independent directors, to further align the interests of our employees and independent directors with the interests of our stockholders, and to closely link compensation with our performance. The exercise price of stock options granted under this plan may not be less than the fair market value of the common stock on the date of grant. The options generally have a term of seven years and vest evenly over three years, except performance based awards, granted to our named executive officers, and options issued to directors. Performance based awards granted under the 2006 Long-Term Incentive Plan vest once the performance criteria have been met. Options granted to our directors vest immediately.

During the three months ended September 30, 2010, we recorded a compensation expense accrual of $245,549 of which $9,430 was allocated to lease operating expenses, $210,360 was allocated to general and administrative expenses, and $25,759 was capitalized to gas properties. During the nine months ended September 30, 2010, we recorded a compensation expense accrual of $373,001 of which $31,626 was allocated to lease operating expenses, $268,450 was allocated to general and administrative expenses, and $72,925 was capitalized to gas properties. The weighted average remaining useful life of the future compensation cost is 1.16 years.

During the three months ended September 30, 2009, we recorded a compensation expense accrual of $203,038 which $8,240 was allocated to lease operating expenses, $151,926 was allocated to general and administrative expenses, and $42,873 was capitalized to gas properties. During the nine months ended September 30, 2009, we recorded a compensation expense accrual of $809,877 which $45,044 was allocated to lease operating expenses, $616,236 was allocated to general and administrative expenses, and $148,598 was capitalized to gas properties.

The significant assumptions used in determining the compensation costs included an expected volatility from 79.3% to 83.7%, risk-free interest rate of 1.47%, an expected term from 4.39 to 4.83 years, forfeiture rates from 5% to 15%, and no expected dividends.

Incentive Stock Options

The table below summarizes incentive stock option activity for the nine months ended September 30, 2010:


	Number of Options			Weighted Average Exercise Price		Average Remaining Contractual Life		Aggregate Intrinsic Value
Outstanding at December 31, 2009		997,786		$	3.95
Granted		600,699		$	0.88
Exercised		(75,190	)	$	0.72
Forfeited		(117,770	)	$	2.92

Outstanding at September 30, 2010		1,405,525		$	2.52		5.46	$	339,763

Options exercisable at September 30, 2010		499,141		$	6.41		3.70	$	60,193

During the three and nine months ended September 30, 2010, 600,699 incentive stock options were granted with a weighted average grant-date fair value of $0.55 per option. The total intrinsic value of the 10,758 incentive stock options exercised during the three months ended September 30, 2010 was $0.24 per option. The total intrinsic value of the 75,190 incentive stock options exercised during the nine months ended September 30, 2010 was $0.41 per option.

The table below summarizes incentive stock option activity for the nine months ended September 30, 2009:


	Number of Options			Weighted Average Exercise Price		Average Remaining Contractual Life		Aggregate Intrinsic Value
Outstanding at December 31, 2008		477,169		$	8.09
Granted		606,507		$	0.72
Transferred		(12,048	)	$	8.30
Forfeited		(53,105	)	$	3.65

Outstanding at September 30, 2009		1,018,523		$	3.93		5.35	$	586,006

Options exercisable at September 30, 2009		338,978		$	8.53		3.55	$	3,449

During the three months ended September 30, 2009, no incentive stock options were granted. During the nine months ended September 30, 2009, 606,507 incentive stock options were granted with a weighted average grant-date fair value of $0.33 per option. No incentive stock options were exercised during the three and nine months ended September 30, 2009.

Non-Qualified Stock Options

The table below summarizes non-qualified stock option activity for the nine months ended September 30, 2010:


	Number of Options			Weighted Average Exercise Price		Average Remaining Contractual Life		Aggregate Intrinsic Value
Outstanding at December 31, 2009		1,400,760		$	3.61
Forfeited		(10,212	)	$	0.72

Outstanding at September 30, 2010		1,390,548		$	3.63		2.80	$	43,596

Options exercisable at September 30, 2010		1,190,020		$	3.37		2.51	$	—

During the three and nine months ended September 30, 2010, no non-qualified stock options were granted or exercised.

The table below summarizes non-qualified stock option activity for the nine months ended September 30, 2009:


	Number of Options			Weighted Average Exercise Price		Average Remaining Contractual Life		Aggregate Intrinsic Value
Outstanding at December 31, 2008		1,280,087		$	3.87
Granted		114,012		$	0.72
Transferred		12,048		$	8.30
Forfeited		(5,387	)	$	13.00

Outstanding at September 30, 2009		1,400,760		$	3.61		3.82	$	110,592

Options exercisable at September 30, 2009		1,114,196		$	3.05		3.44	$	—

During the three months ended September 30, 2009, no non-qualified stock options were granted. During the nine months ended September 30, 2009, 114,012 non-qualified stock options were granted with a weighted average grant-date fair value of $0.33 per option. During the three and nine months ended September 30, 2009, no non-qualified stock options were exercised.

Restricted Stock Awards

The table below summarizes non-vested restricted stock awards activity for the nine months ended September 30, 2010:


	Number of Shares			Weighted Average Value at Grant Date
Non-vested restricted stock at December 31, 2009		311,684		$	6.57
Granted		132,492		$	0.88
Vested		(85,470	)	$	6.74
Forfeited		(66,194	)	$	6.50

Non-vested restricted stock at September 30, 2010		292,512		$	3.95

During the three and nine months ended September 30, 2010, 132,492 shares of restricted stock were granted with a weighted average grant-date fair value of $0.88 per share. During the three months ended September 30, 2010, 1,708 shares of restricted stock vested with a grant date fair value of $5.95 per share. During the nine months ended September 30, 2010, 85,470 shares of restricted stock vested with a grant date fair value of $6.74 per share.

The table below summarizes non-vested restricted stock awards activity for the nine months ended September 30, 2009:


	Number of Shares			Weighted Average Value at Grant Date
Non-vested restricted stock at December 31, 2008		401,075		$	6.60
Forfeited		(4,624	)	$	6.58
Vested		(78,037	)	$	3.98

Non-vested restricted stock at September 30, 2009		318,414		$	7.24

During the three and nine months ended September 30, 2009, no shares of restricted stock were granted. During the three months ended September 30, 2009, 9,740 shares of restricted stock vested with a grant date fair value of $5.95. During the nine months ended September 30, 2009, 78,037 shares of restricted stock vested with a grant date fair value of $3.98 per share.

Note 12 — Commitments and Contingencies

From time to time we are a party to litigation in the normal course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not believe that the adverse effect on our financial condition, results of operations or cash flows, if any, will be material.

Environmental and Regulatory

As of September 30, 2010, there were no known environmental or other regulatory matters related to our operations that are reasonably expected to result in a material liability to us.

Note 13 — Income Taxes

Our effective tax rate differs from the federal statutory rate primarily due to net operating losses (“NOL’s”) in Canada and certain states from which we are currently unable to benefit, as well as state income taxes. The deferred tax asset related to the Canadian and certain state NOL’s are fully reserved because it is more likely than not that we will not use those NOL’s to offset existing tax liabilities in future years. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to September 30, 2011. For tax reporting purposes, we have federal and state NOL’s of approximately $109.4 million and $117.5 million, respectively, at September 30, 2010 that are available to reduce future taxable income. If not utilized, the federal carryforwards would begin to expire in 2022. Certain immaterial portions of the state NOL’s will expire prior to 2022. Our ability to use our NOL’s is not currently impacted by Internal Revenue Code Section 382 limitations.

Income tax expense for the three months ended September 30, 2010 was different than the amount computed using the statutory rate as follows:


	U.S.				Canada					Total
Amount computed using statutory rates	$	2,880,048	34.0	%	$	(34,045	)	26.0	%	$	2,846,003	34.1	%
State income taxes—net of federal benefit		446,211	5.3	%		—		0.0	%		446,211	5.4	%
Valuation Allowance		—	0.0	%		34,045		-26.0	%		34,045	0.4	%
Nondeductible items and other (1)		486,329	5.7	%		—		0.0	%		486,329	5.8	%

Income tax provision	$	3,812,588	45.0	%	$	—		0.0	%	$	3,812,588	45.7	%

Income tax expense for the three months ended September 30, 2009 was different than the amount computed using the statutory rate as follows:


	U.S.					Canada					Total
Amount computed using statutory rates	$	(24,725,666	)	34.0	%	$	(885,764	)	26.0	%	$	(25,611,430	)	33.6	%
State income taxes—net of federal benefit		(2,884,551	)	4.0	%		—		0.0	%		(2,884,551	)	3.8	%
Valuation Allowance		—		0.0	%		885,764		-26.0	%		885,764		-1.1	%
Nondeductible items and other		(176,129	)	0.2	%		—		0.0	%		(176,129	)	0.2	%

Income tax benefit	$	(27,786,346	)	38.2	%	$	—		0.0	%	$	(27,786,346	)	36.5	%

Income tax expense for the nine months ended September 30, 2010 was different than the amount computed using the statutory rate as follows:


	U.S.				Canada					Total
Amount computed using statutory rates	$	5,688,977	34.0	%	$	(209,043	)	26.0	%	$	5,479,934	34.4	%
State income taxes—net of federal benefit		827,021	4.9	%		—		0.0	%		827,021	5.2	%
Valuation Allowance		—	0.0	%		209,043		-26.0	%		209,043	1.3	%
Nondeductible items and other (1)		620,049	3.7	%		—		0.0	%		620,049	3.9	%

Income tax provision	$	7,136,047	42.6	%	$	—		0.0	%	$	7,136,047	44.8	%

Income tax expense for the nine months ended September 30, 2009 was different than the amount computed using the statutory rate as follows:


	U.S.					Canada					Total
Amount computed using statutory rates	$	(81,861,937	)	34.0	%	$	(1,710,641	)	26.0	%	$	(83,572,578	)	33.8	%
State income taxes—net of federal benefit		(9,535,122	)	4.0	%		—		0.0	%		(9,535,122	)	3.9	%
Valuation Allowance		—		0.0	%		1,710,641		-26.0	%		1,710,641		-0.7	%
Nondeductible items and other		(497,750	)	0.2	%		—		0.0	%		(497,750	)	0.2	%

Income tax benefit)	$	(91,894,809	)	38.2	%	$	—		0.0	%	$	(91,894,809	)	37.2	%

(1)	Includes tax expense of $536,592 related to terminated transaction costs of $1,402,534 that were expensed for financial reporting purposes but not deductible for tax reporting purposes.

Note 14 — Subsequent Event

On November 10, 2010, Sherwood Energy, LLC executed a written consent approving a proposed amendment to the Certificate of Designations of Series A Convertible Redeemable Preferred Stock. The proposed amendment would adjust the anti-dilution provision in the Certificate of Designations. Under the current anti-dilution provision, if the Company issued additional shares of common stock (or securities convertible into common stock) without consideration or for a consideration per share less than the then-existing conversion price of the Preferred Stock, then the conversion price would be reduced to the price per share received by the Company for such additional issuance. Under the proposed amendment, the anti-dilution provision would be revised such that the conversion price would be reduced to a price determined by multiplying such conversion price by a fraction (a) the numerator of which will be the sum of (i) the number of shares of common stock outstanding before the additional issuance plus (ii) the number of shares of common stock which the aggregate consideration received by the Company for the additional issuance would purchase at the conversion price then in effect, and (b) the denominator of which will be the sum of (x) the number of shares of common stock outstanding before the additional issuance plus (y) the number of such additional shares of common stock that were actually issued.

The proposed amendment also would prohibit the Company from issuing any additional shares of common stock (or securities convertible into common stock) for consideration per share (with regard to securities convertible into common stock, on an as-converted basis) less than the then-current conversion price of the Preferred Stock without the prior vote or consent of holders of a majority of the outstanding shares of Preferred Stock, for so long as at least 750,000 shares of Preferred Stock remain outstanding. The proposed amendment to the Certificate of Designations cannot become effective until at least twenty calendar days following the filing by the Company of a definitive information statement describing the proposed amendment.

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Statement Regarding Forward-Looking Information

Management’s Discussion and Analysis of Financial Condition and Results of Operations and other items in this Quarterly Report on Form 10-Q contain forward-looking statements and information that are based on management’s beliefs, as well as assumptions made by, and information currently available to, management. When used in this document, the words “believe,” “anticipate,” “estimate,” “expect,” “intend,” and similar expressions are intended to identify forward-looking statements. Although management believes that the expectations reflected in these forward-looking statements are reasonable, it can give no assurance that these expectations will prove to have been correct. These statements are subject to certain risks, uncertainties and assumptions. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated. We undertake no obligation to release publicly any revisions to these forward-looking statements that may be made to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

You should read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in conjunction with the corresponding sections and our audited consolidated financial statements for the fiscal year ended December 31, 2009, which are included in our Annual Report on Form 10-K, as amended, for the year ended December 31, 2009, that we filed with the Securities Exchange Commission.

Overview

GeoMet, Inc. is an independent energy company primarily engaged in the exploration for and development and production of natural gas from coal seams (“coalbed methane” or “CBM”) and non-conventional shallow gas. We were originally founded as a consulting company to the coalbed methane industry in 1985 and have been active as an operator and developer of coalbed methane properties since 1993. 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, Virginia, and West Virginia. As of September 30, 2010, we control a total of approximately 160,000 net acres of coalbed methane and oil and gas development rights.

Our ability to successfully leverage our competitive strengths and execute our strategy depends upon many factors and is subject to a variety of risks. For example, our ability to drill on our properties and fund our capital budgets may depend, to a large extent, upon our ability to generate cash flow from operations at or above current levels, maintain borrowing capacity at or near current levels under our revolving credit facility, and the availability of future debt and equity financing on satisfactory terms. Our ability to fund new opportunities and compete for and retain the qualified personnel necessary to conduct our business is also dependent upon our financial resources. Prolonged weakness in the global economy and in natural gas prices, which may affect both our cash flows and the value of our gas reserves, limitations on our ability to replace production through drilling activities, a material adverse change in our gas reserves due to factors other than gas pricing changes, our ability to transport our gas to markets, drilling costs, lower than expected production rates and other factors, many of which are beyond our control, may adversely affect our ability to fund our anticipated capital expenditures, pursue property acquisitions, and compete for qualified personnel, among other things.

Changes in natural gas prices may significantly affect our revenues, financial condition, cash flows, natural gas reserves and borrowing capacity. Markets for natural gas have historically been volatile and we expect this trend to continue. Prices for natural gas may fluctuate in response to changes in supply and demand, market uncertainty, seasonal, political and other factors beyond our control. We are unable to accurately predict the prices we will receive for our natural gas. Accordingly, any significant or sustained declines in natural gas prices may materially adversely affect our financial condition, operating results, liquidity and ability to obtain financing. Declining or prolonged low natural gas prices may also result in non-compliance with the covenants in our revolving credit facility agreement and could result in a lower determination of our borrowing base. Although we will attempt to cure any non-compliance with covenants in our revolving credit facility in the event they occur, no assurance can be given that we will be able to cure such non-compliance. Lower natural gas prices also may reduce the amount of natural gas that we can produce economically. Further declines in natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our proved natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Our capital expenditure budgets are highly dependent on future natural gas prices.

Recent Developments

Revolving Credit Facility

Our Fourth Amended and Restated Credit Agreement (the “Credit Agreement”) became effective on September 14, 2010 upon the completion of our rights offering and backstop transaction. The Credit Agreement replaced our Third Amended and Restated Credit Agreement and provides for revolving credit borrowings of up to $180 million with an initial borrowing base of $90 million.

The borrowing base will be determined as of each June and December with the next determination scheduled to be completed by December 2010. All outstanding borrowings under the Credit Agreement become due and payable on September 14, 2013. The Credit Agreement provides for interest to accrue at a rate calculated, at the Company’s option, at the Adjusted Base Rate plus a margin of 1.75% to 2.25% or the London Interbank Offered Rate (the “LIBOR Rate”) rate plus a margin of 2.75% to 3.25%. Adjusted Base Rate is defined to be the greater of (i) the agent’s base rate or (ii) the federal funds rate plus one half of one percent or (iii) the LIBOR Rate plus a margin of 1.00%). In all cases the applicable margin is dependent on the percentage of borrowing base usage. Under the Credit Agreement we are subject to certain financial covenants requiring maintenance of (i) a minimum Current Ratio, (ii) a maximum Debt Ratio and, (iii) depending on our Debt Ratio, either (a) a minimum Interest Coverage Ratio or (b) a minimum Fixed Charge Ratio. The Current Ratio of consolidated current assets (defined to include amounts available under our borrowing base) to consolidated current liabilities (defined to exclude up to $1.5 million in accrued and unpaid preferred dividends) is not permitted to be less than 1.0 to 1.0 as of the end of any fiscal quarter. The Debt Ratio (defined as funded debt at the end of each fiscal quarter to trailing four quarter consolidated EBITDA) at the end of each fiscal quarter cannot exceed 4.5 to 1.0 through the quarter ending June 30, 2011 and 4.0 to 1.0 thereafter. If our Debt Ratio at the end of each fiscal quarter is above 3.5 to 1.0, then the Fixed Charge Ratio (defined as consolidated EBITDA less capital expenditures to consolidated net cash interest expense for the four preceding quarters) is applicable and cannot be less than 1.25 to 1.0. If our Debt Ratio at the end of each fiscal quarter is 3.5 to 1.0 or less, the Interest Coverage Ratio (defined as consolidated EBITDA to consolidated net cash interest expense plus letter of credit fees accruing during the preceding four quarters) is applicable and cannot be less than 2.75. Consolidated EBITDA is defined as earnings (loss) before deducting net interest expense, income taxes, depreciation, depletion and amortization and also excludes non-recurring charges and other non-cash charges deducted in determining net income (loss), which would include unrealized gains and losses from a change in the market value of open derivative contracts. We are also subject to covenants restricting or prohibiting cash dividends and other restricted payments, transactions with affiliates, incurrence of debt, consolidations and mergers, the level of operating leases, assets sales, investments in other entities, and liens on properties. Cash dividends on our preferred stock are permitted if, following any such cash payment our availability is equal to or greater than 15% of the then current borrowing base and our Debt Ratio is less than 3.5 to 1.0. There are no restrictions associated with the payment of PIK dividends on our preferred stock. As of September 30, 2010, we had $79.5 million of borrowings outstanding under our revolving credit facility, resulting in a borrowing availability of $10.5 million under our $90.0 million borrowing base.

Completion of Rights Offering and Backstop Transaction

On September 14, 2010, the Company issued and sold 4,000,000 shares of Series A Convertible Redeemable Preferred Stock at $10.00 per share in connection with a rights offering and backstop transaction. After paying transaction fees and expenses, the Company used the net proceeds of approximately $37.8 million to reduce outstanding bank debt and for general corporate purposes. The Preferred Stock is our most senior equity security, ranking senior to our common stock and junior to all of our existing indebtedness. See “Liquidity and Capital Resources – Completion of Rights Offering and Backstop Transaction” for additional information.

NASDAQ Deficiency Letter

On September 28, 2010, the Company received a deficiency letter from the staff of The NASDAQ Stock Market, advising the Company that, for the previous 30 consecutive business days, the bid price for the Company’s common stock had closed below the minimum $1.00 per share required under NASDAQ Marketplace Rule 5450(a)(1) for continued listing on the NASDAQ Global Market. The notification letter states that the Company will be afforded 180 calendar days to regain compliance with the minimum bid price requirement. In order to regain compliance, the bid price of the Company’s common stock must close at $1.00 per share or more for a minimum of ten consecutive business days.

The initial grace period expires on March 28, 2011. In the event that the bid price deficiency is not cured by that time, the Company’s securities will be subject to delisting. An additional 180-day period will be available to regain compliance if the Company transfers its listing to the NASDAQ Capital Market and meets all other listing requirements. The Company intends to actively monitor the bid price for its common stock between now and March 28, 2011, and will consider all available options to resolve the deficiency and regain compliance with the NASDAQ Global Market minimum bid price requirement. The notification letter has no effect on the listing or trading of the Company’s common stock and preferred stock on the NASDAQ Global Market at this time.

Operational Developments

Pond Creek— In our Pond Creek Field, net gas sales volumes averaged approximately 14.7 MMcf/day for the third quarter of 2010, up over 2% from the same period last year and over 1% from the prior quarter. At the end of the quarter, we had drilled 14 gross (12.5 net) new wells in Virginia. Nine of those wells are currently on line, averaging approximately 90 Mcf per day per well compared to a current field wide average of 74 Mcf per day per well. We expect production from this group of wells to continue to incline. Six more wells will be

drilled in the fourth quarter and we expect to add a total of 11 additional wells to sales during the fourth quarter. Based on these plans we expect the year-end exit gas sales volumes at Pond Creek to be above current levels. We plan to drill at least 20 wells annually in the Virginia portion of the Pond Creek field through 2013. We believe we can grow total Company production modestly over the next four or more years just from drilling these wells.

Lasher— No new wells were added to sales in the three months ended September 30, 2010. Net gas sales averaged 0.4 MMcf per day from 18 producing wells for the three months ended September 30, 2010, as compared to 0.3 MMcf per day for the three months ended September 30, 2009.

Gurnee— In the Gurnee field in the Cahaba Basin, our net gas sales volumes averaged approximately 4.9 MMcf/day for the third quarter of 2010, down slightly from the prior quarter and down approximately 14% when compared to the same period last year. Until recently, we had not drilled a new well in the Gurnee field in almost two years. The decrease in year over year production at Gurnee reflects not only normal annual production declines, but also the shutting in of 26 wells due to low natural gas prices and certain operational issues. In the third quarter of 2009 we began to believe that fracture conductivity loss after commencing production was a main contributor to underperforming production, and that our Gurnee wells are draining only a small area around each wellbore. Starting late in the third quarter of 2009 we temporarily plugged off production from three wells and conducted three different new frac techniques in upper coal seams that were behind pipe. One of these techniques, which involved using a shale-like frac technique in the surrounding strata rather than directly into the coal seams, generated particularly encouraging results. This technique was then applied to one of the other two wells, also with good results. Earlier this year we tried this frac technique in two existing, previously fraced full wellbores but we were unsuccessful in isolating the existing perforations and these efforts failed. In the third quarter of this year we temporarily plugged off production in four additional wells and again completed upper coal seams that were behind pipe using this frac technique. Production results from three of these four wells has exceeded our predictions; the fourth well is still producing high water volumes. When we have been successful in getting the frac into the strata surrounding the coalseams, we have had consistently good results. More recently, we have drilled a new well in the Gurnee field in order to test this technique on a full wellbore without the complication of existing perforations. We plan to complete this well in three segments so we can evaluate the production characteristics from individual coal groups.

Garden City— In our Garden City Chattanooga Shale prospect, the Alabama Oil & Gas Board approved our proposal to inject produced water into one of our existing vertical wells which will also allow us to resume gas production from two existing horizontal wells without having to truck the produced water at prohibitive costs.

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires us to use our judgment to make estimates and assumptions that affect certain amounts reported in our financial statements. As additional information becomes available, these estimates and assumptions are subject to change and thus impact amounts reported in the future. Critical accounting policies are those accounting policies that involve judgment and uncertainties affecting the application of those policies and the likelihood that materially different amounts would be reported under different conditions or using differing assumptions. We periodically update our estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. There has been the following significant change to our critical accounting policies during the nine months ended September 30, 2010:

Convertible Redeemable Preferred Stock– The Series A Convertible Redeemable Preferred Stock has been classified within the mezzanine (temporary) equity section of the Consolidated Balance Sheets (Unaudited) because the shares are redeemable at the option of the holder and therefore do not qualify for permanent equity. In addition, we evaluated the conversion feature and have determined that its terms require the holder’s conversion option to be separated and recorded at fair value as a derivative liability on the Consolidated Balance Sheets (Unaudited). Subsequent changes in the fair value of the derivative liability will be recorded as a component of other income and expense in the Consolidated Statements of Operations (Unaudited). The fair value of the derivative liability attributable to the conversion option was determined using an American binomial lattice model, which utilized assumptions including 80% volatility, a 17% discount factor and an expected term of 6.4 years determined using a Monte Carlo simulation model, and resulted in a fair value of approximately $18.4 million on the date of issuance. The remaining net proceeds of $20.4 million were allocated to Series A Convertible Redeemable Preferred Stock in the Consolidated Balance Sheets (Unaudited) at September 30, 2010. For the three and nine months ended September 30, 2010, the Company recorded approximately $1.6 million to Unrealized gain from change in fair value of derivative liability - Series A Convertible Redeemable Preferred Stock in the Consolidated Statements of Operations (Unaudited) as a result of the change in the fair value of the derivative liability. The $1.6 million gain in the current quarter was primarily the result of the decrease in the market price of our stock from the issuance date of our Series A Convertible Redeemable Preferred Stock of September 14, 2010 through the end of the current quarter.

Producing Fields Operations Summary

The table below presents information on gas sales, net sales volumes, production expenses and per Mcf data for the three and nine months ended September 30, 2010 and 2009. This table should be read in conjunction with the discussion of the results of operations for the periods presented below (in thousands).


	Three Months Ended September 30,				Nine months Ended September 30,
	2010		2009		2010		2009

Gas sales	$	8,239	$	6,393	$	25,784	$	22,684

Lease operating expenses	$	2,877	$	3,195	$	8,798	$	11,112
Compression and transportation expenses		1,096		1,235		3,176		4,050
Production taxes		227		248		723		856

Total production expenses	$	4,200	$	4,678	$	12,696	$	16,018

Net sales volumes (MMcf)		1,845		1,901		5,490		5,690
Pond Creek field		1,349		1,318		3,962		3,920
Gurnee field		455		527		1,396		1,620
Per Mcf data ($/Mcf):
Average natural gas sales price	$	4.47	$	3.36	$	4.70	$	3.99
Average natural gas sales price realized(1)	$	5.45	$	5.03	$	5.70	$	5.50
Lease operating expenses	$	1.56	$	1.68	$	1.60	$	1.95
Pond Creek field	$	1.17	$	1.27	$	1.25	$	1.38
Gurnee field	$	2.54	$	2.30	$	2.31	$	2.74
Compression and transportation expenses	$	0.60	$	0.65	$	0.58	$	0.71
Pond Creek field	$	0.65	$	0.64	$	0.63	$	0.71
Gurnee field	$	0.45	$	0.50	$	0.40	$	0.56
Production taxes	$	0.12	$	0.13	$	0.13	$	0.15
Pond Creek field	$	0.16	$	0.11	$	0.17	$	0.12
Gurnee field (2)	$	0.01	$	0.19	$	0.05	$	0.23
Total production expenses	$	2.28	$	2.46	$	2.31	$	2.81
Pond Creek field	$	1.98	$	2.02	$	2.05	$	2.21
Gurnee field	$	3.00	$	2.99	$	2.76	$	3.53
Depreciation, depletion and amortization	$	0.85	$	2.72	$	0.85	$	1.79

(1)	Average realized price includes the effects of realized gains on derivative contracts.

(2)	The Company received production tax refunds related to prior production in the Gurnee field in March and August 2010.

Results of Operations

Three months ended September 30, 2010 compared with three months ended September 30, 2009

The following are selected items derived from our Consolidated Statements of Operations (Unaudited) and their percentage changes from the comparable period are presented below.


	Three months ended September 30,				Change
	2010		2009		Change
	(In thousands)
Gas sales	$	8,239	$	6,393		29	%
Lease operating expenses	$	2,877	$	3,195		-10	%
Compression expense	$	777	$	921		-16	%
Transportation expense	$	319	$	314		2	%
Production taxes	$	227	$	248		8	%
Impairment of gas properties	$	—	$	69,146		-100	%
Depreciation, depletion and amortization	$	1,561	$	5,169		-70	%
General and administrative	$	1,206	$	1,853		-35	%


	Three months ended September 30,						Change
	2010			2009			Change
	(In thousands)
Realized gains on derivative contracts	$	(1,825	)	$	(3,169	)		-42	%
Unrealized (gains) losses from the change in market value of open derivative contracts	$	(5,096	)	$	3,567			NM
Interest expense, net of amounts capitalized	$	1,510		$	1,386			9	%
Unrealized gain from change in fair value of derivative liability - Series A Convertible Redeemable Preferred Stock	$	(1,596	)	$	—			NM
Income tax expense (benefit)	$	3,813		$	(27,786	)		NM

NM-Not Meaningful

Gas sales. Gas sales increased by $1.85 million, or 29%, to $8.24 million compared to the prior year quarter. The increase in gas sales was a result of increased gas prices partially offset by decreased production. Production decreased 3% and average gas prices increased 33%, excluding hedging transactions. The $1.85 million increase in gas sales consisted of a $2.03 million increase in prices and a $0.18 million decrease in production. The decrease in production was primarily due to the shutting in of certain uneconomic wells, as a result of low gas prices.

Lease operating expenses. Lease operating expenses decreased by $0.32 million, or 10%, to $2.88 million compared to the prior year quarter. The decrease in lease operating expenses consisted of a $0.22 million decrease in costs and a $0.10 million decrease in production. The $0.22 million decrease in costs was primarily due to the continued success of a company-wide cost reduction strategy implemented in April 2009.

Compression expense. Compression expense decreased by $0.14 million, or 16%, to $0.78 million compared to the prior year quarter. The $0.14 million decrease was comprised of a $0.11 million decrease in costs and a $0.03 million decrease in production. The $0.11 million decrease in costs was primarily due to the continued success of a company-wide cost reduction strategy implemented in April 2009.

Transportation expense. Transportation expense remained materially unchanged compared to the prior year quarter.

Production taxes. Production taxes decreased by $0.02 million, or 8%, to $0.23 million compared to the prior year quarter. The $0.02 million decrease in production taxes was primarily due to a production tax refund in the current period, partially offset by an increase in production taxes due to the phase-in of state taxes on production of natural gas in the West Virginia portion of our Pond Creek field.

Impairment of gas properties. At September 30, 2009, the carrying value of the Company’s gas properties exceeded the full cost ceiling limitation. There was no such impairment recorded in the current year period.

Depreciation, depletion and amortization. Depreciation, depletion and amortization decreased by $3.61 million, or 70%, to $1.56 million compared to the prior year quarter. The depreciation, depletion and amortization decrease consisted of a $0.15 million decrease in production and a $3.46 million decrease in the depletion rate. The decrease in the depletion rate was due to the ceiling write-downs incurred throughout 2009.

General and administrative. General and administrative expenses decreased by $0.65 million, or 35%, to $1.21 million compared to the prior year quarter. The decrease in general and administrative expenses was primarily due to the continued success of a company-wide cost reduction strategy implemented in April 2009.

Realized gains on derivative contracts. Realized gains on derivative contracts decreased by $1.34 million, or 42%, to $1.83 million compared to the prior year quarter. Realized losses represent net cash flow settlements paid to the counterparty, while realized gains represent net cash flow settlements paid to us from the counterparty. Realized losses occur when natural gas prices exceed the derivative ceiling prices. Conversely, realized gains occur when natural gas prices go below the derivative floor prices.

Unrealized (gains) losses from the change in market value of open derivative contracts. Unrealized gains from the change in market value of open derivative contracts were $5.10 million compared to unrealized losses of $3.57 million in the prior year quarter. Unrealized losses and gains are non-cash transactions that occur when the corresponding asset or liability derivative contracts are marked to market at the end of each reporting period. The gains were primarily due to the increased estimated fair value of our natural gas derivative contracts resulting from decreased natural gas prices.

Interest expense. Interest expense increased by $0.12 million, or 9%, to $1.51 million compared to the prior year quarter. The increase is comprised of a $0.13 million increase in interest related to the increased interest rate under our new Credit Agreement that became effective September 14, 2010 and a $0.16 million increase in amortization of loan costs related to the revolving credit facility, partially offset by a $0.17 million decreased realized loss on interest rate swaps.

Unrealized gain from change in fair value of derivative liability - Series A Convertible Redeemable Preferred Stock. The gain in the current period was primarily the result of the decrease in the market price of our stock from the issuance date of our Series A Convertible Redeemable Preferred Stock of September 14, 2010 through the end of the current period.

Income tax expense (benefit). Income tax expense was $3.81 million in the current year period. The effective tax rate for the period was 45.7%. Income tax benefit for the three months ended September 30, 2010 was different than the amount computed using the statutory rate as follows:


	U.S.				Canada					Total
Amount computed using statutory rates	$	2,880,048	34.0	%	$	(34,045	)	26.0	%	$	2,846,003	34.1	%
State income taxes—net of federal benefit		446,211	5.3	%		—		0.0	%		446,211	5.4	%
Valuation Allowance		—	0.0	%		34,045		-26.0	%		34,045	0.4	%
Nondeductible items and other		486,329	5.7	%		—		0.0	%		486,329	5.8	%

Income tax provision	$	3,812,588	45.0	%	$	—		0.0	%	$	3,812,588	45.7	%

Nine months ended September 30, 2010 compared with nine months ended September 30, 2009

The following are selected items derived from our Consolidated Statements of Operations (Unaudited) and their percentage changes from the comparable period are presented below.


	Nine months ended September 30,						Change
	2010			2009			Change
	(In thousands)
Gas sales	$	25,784		$	22,684			14	%
Lease operating expenses	$	8,798		$	11,113			-21	%
Compression expense	$	2,219		$	2,703			-18	%
Transportation expense	$	957		$	1,347			-29	%
Production taxes	$	723		$	856			-16	%
Impairment of gas properties	$	—		$	236,441			-100	%
Depreciation, depletion and amortization	$	4,657		$	10,187			-54	%
General and administrative	$	3,999		$	7,006			-43	%
Terminated transaction costs	$	1,403		$	—			NM
Realized gains on derivative contracts	$	(5,496	)	$	(8,626	)		-36	%
Unrealized (gains) losses from the change in market value of open derivative contracts	$	(9,764	)	$	5,526			NM
Interest expense, net of amounts capitalized	$	4,177		$	3,787			10	%
Unrealized gain from change in fair value of derivative liability - Series A Convertible Redeemable Preferred Stock	$	(1,596	)	$	—			NM
Income tax expense (benefit)	$	7,136		$	(91,895	)		NM

NM-Not Meaningful

Gas sales. Gas sales increased by $3.10 million, or 14%, to $25.78 million compared to the prior year period. The increase in gas sales was a result of increased gas prices partially offset by decreased production. Production decreased 4% and average gas prices increased 18%, excluding hedging transactions. The $3.10 million increase in gas sales consisted of a $3.90 million increase in prices and a $0.80 million decrease in production. The decrease in production was primarily due to the shutting in of certain uneconomic wells, as a result of low gas prices.

Lease operating expenses. Lease operating expenses decreased by $2.32 million, or 21%, to $8.80 million compared to the prior year period. The decrease in lease operating expenses consisted of a $1.93 million decrease in costs and a $0.39 million decrease in production. The $1.93 million decrease in costs was primarily due to a company-wide cost reduction strategy implemented in April 2009.

Compression expense. Compression expense decreased by $0.48 million, or 18%, to $2.22 million compared to the prior year period. The $0.48 million decrease was comprised of a $0.39 million decrease in costs and a $0.09 million decrease in production. The $0.39 million decrease in costs was primarily due to a company-wide cost reduction strategy implemented in April 2009.

Transportation expense. Transportation expense decreased by $0.39 million, or 29%, to $0.96 million compared to the prior year period. The $0.39 million decrease was primarily due to a $0.34 million decrease in costs resulting from the permanent release of excess firm transportation capacity effective May 1, 2009 and a $0.05 million decrease in production.

Production taxes. Production taxes decreased by $0.13 million, or 16%, to $0.72 million compared to the prior year period. The $0.13 million decrease in production taxes was primarily due to production tax refunds in the current period, partially offset by an increase in production taxes due to the phase-in of state taxes on production of natural gas in the West Virginia portion of our Pond Creek field.

Depreciation, depletion and amortization. Depreciation, depletion and amortization decreased by $5.53 million, or 54%, to $4.66 million compared to the prior year period. The depreciation, depletion and amortization decrease consisted of a $0.36 million decrease in production and a $5.17 million decrease in the depletion rate. The decrease in the depletion rate was due to the ceiling write-downs incurred throughout 2009.

Terminated transaction costs. During the current period, we incurred $1.34 million of costs related to a proposed financing transaction with certain parties and $0.06 million related to a potential sale of certain assets. Negotiations with those parties ceased and the related costs were expensed as terminated transaction costs. No such expenses were incurred in the prior year period.

General and administrative. General and administrative expenses decreased by $3.01 million, or 43%, to $4.00 million compared to the prior year period. The decrease in general and administrative expenses was primarily due to a company-wide cost reduction strategy implemented in April 2009.

Realized gains on derivative contracts. Realized gains on derivative contracts decreased by $3.13 million, or 36%, to $5.50 million compared to the prior year period. Realized losses represent net cash flow settlements paid to the counterparty, while realized gains represent net cash flow settlements paid to us from the counterparty. Realized losses occur when natural gas prices exceed the derivative ceiling prices. Conversely, realized gains occur when natural gas prices go below the derivative floor prices.

Unrealized (gains) losses from the change in market value of open derivative contracts. Unrealized gains from the change in market value of open derivative contracts were $9.76 million in the current period as compared to unrealized losses of $5.53 million in the prior year period. Unrealized losses and gains are non-cash transactions that occur when the corresponding asset or liability derivative contracts are marked to market at the end of each reporting period. The gain was a result of the increased estimated fair value of our natural gas derivative contracts resulting from decreased natural gas prices.

Interest expense. Interest expense increased by $0.39 million, or 10%, to $4.18 million compared to the prior year period. The increase is comprised of a $0.25 million increase in interest related to the increased interest rate under our new Credit Agreement that became effective September 14, 2010 and a $0.37 million increase in amortization of loan costs related to the revolving credit facility, partially offset by a $0.23 million decreased realized loss on interest rate swaps.

Income tax expense (benefit). Income tax expense was $7.14 million in the current year period. The effective tax rate for the period was 44.8%. Income tax expense for the nine months ended September 30, 2010 was different than the amount computed using the statutory rate as follows:


	U.S.				Canada					Total
Amount computed using statutory rates	$	5,688,977	34.0	%	$	(209,043	)	26.0	%	$	5,479,934	34.4	%
State income taxes—net of federal benefit		827,021	4.9	%		—		0.0	%		827,021	5.2	%
Valuation Allowance		—	0.0	%		209,043		-26.0	%		209,043	1.3	%
Nondeductible items and other		620,049	3.7	%		—		0.0	%		620,049	3.9	%

Income tax provision	$	7,136,047	42.6	%	$	—		0.0	%	$	7,136,047	44.8	%

Liquidity and Capital Resources

Cash Flows and Liquidity

Cash flows provided by operations for the nine months ended September 30, 2010 and 2009 were $11.7 million and $6.9 million, respectively. As of September 30, 2010, we had working capital of approximately $2.5 million. As of December 31, 2009, we

had a working capital deficit of less than $0.1 million. We believe that our cash flow from operations and other financial resources such as borrowings under our revolving credit facility will provide us with sufficient capital resources to meet our projected capital expenditures for the next twelve months.

If natural gas prices remain at a depressed level for an extended period, our ability to finance our planned capital expenditures could be affected negatively. Consistent with our intention to keep our capital expenditures in line with our estimated operating cash flows, further reduction in spending may be necessary. Furthermore, amounts available for borrowing under our revolving credit facility are largely dependent on our level of estimated proved reserves and our lender’s expectation of future natural gas prices and cash flows. If either our estimated proved reserves or natural gas prices decrease significantly, funding available to us under our revolving credit facility could be further negatively affected. If our cash flows are less than anticipated or amounts available for borrowing under our revolving credit facility are reduced, we may be forced to defer planned capital expenditures.

The ongoing disruption in the credit markets has had a significant adverse impact on a number of financial institutions. We have reviewed the creditworthiness of the banks and financial institutions with which we maintain our cash and short-term investments. Thus far, our liquidity and financial position have not been impacted, and we do not expect that it will be materially impacted in the future. However, we cannot predict with any certainty the impact of any further disruption in the credit markets.

Completion of Rights Offering and Backstop Transaction

On September 14, 2010, the Company issued and sold 4,000,000 shares of Series A Convertible Redeemable Preferred Stock (“Preferred Stock”), par value $0.001 per share, at a price of $10.00 per share. After paying transaction fees and expenses, the Company used the net proceeds of approximately $37.8 million to reduce outstanding bank debt and for general corporate purposes. The Preferred Stock is our most senior equity security. The Preferred Stock ranks senior to our common stock and junior to all of our existing indebtedness.

dividends) are entitled to receive, prior and in preference to any payment, or segregation for payment, of any consideration to any holder of any junior security of the Company, an amount in cash equal to the greater of (i) $10.00 per share, plus any accrued but unpaid dividends (in each case adjusted for any stock dividends, splits, combinations or similar events), or (ii) an amount equal to the amount such holders of the Preferred Stock would have received upon the Liquidation Event if they had converted their shares of Preferred Stock into shares of our common stock.

During the three and nine months ended September 30, 2010, the Company declared no dividends to the holders of Preferred Stock. However, PIK dividends of $236,111 or $0.059028 per share of Preferred Stock were accrued in the Consolidated Balance Sheets (Unaudited) at September 30, 2010 using the PIK dividend rate of 12.5% for the period of September 14, 2010 through September 30, 2010. $137,046 was accrued to Preferred Stock and $99,065 was accrued to Derivative liability - Series A Convertible Redeemable Preferred Stock on the Consolidated Balance Sheet (Unaudited) at September 30, 2010 because quarterly dividends are cumulative.


	Mezzanine Equity - Series A Convertible Redeemable Preferred Stock			Derivative Liability - Series A Convertible Redeemable Preferred Stock			Total Liability & Mezzanine Equity Amounts Related to Series A Convertible Redeemable Preferred Stock

Balance at January 1, 2010	$	—		$	—		$	—
Issuance of Series A Convertible Redeemable Preferred Stock		40,000,000			—			40,000,000
Allocated to derivative liability		(18,378,517	)		18,378,517			—
Issuance costs (1)		(1,211,664	)		—			(1,211,664	)

Net issuance of Series A Convertible Redeemable Preferred Stock		20,409,819			18,378,517			38,788,336
Unrealized gain from change in fair value of derivative liability - Series A Convertible Redeemable Preferred Stock		—			(1,595,670	)		(1,595,670	)
Accretion of Series A Convertible Redeemable Preferred Stock		73,532			—			73,532
PIK Dividend accrual for Series A Convertible Redeemable Preferred Stock		137,046			99,065			236,111

Balance at September 30, 2010	$	20,620,397		$	16,881,912		$	39,097,979

(1)

Subsequent Event

Once the proposed amendment is effective, the bifurcated derivative liability on the Consolidated Balance Sheets (Unaudited) related to the conversion feature will be reclassified to paid-in capital on the Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss). In addition, we will not experience the volatility on Consolidated Statement of Operations from unrealized gains or losses resulting from future fair value fluctuations of the extinguished derivative liability.

Price Risk Management Activities

The energy markets have historically been volatile, and there can be no assurance that future natural gas prices will not be subject to wide fluctuations. In an effort to reduce the effects of the volatility of the price of natural gas on our operations, management has adopted a policy of hedging natural gas prices from time to time primarily using derivative instruments in the form of three-way collars, traditional collars and swaps. While the use of these hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements. Our price risk management policy strictly prohibits the use of derivatives for speculative positions.

We enter into hedging transactions, generally for forward periods of two or more years, which increase the probability of achieving our targeted level of cash flows. We generally limit the amount of these hedges during any period to no more than 50% to 70% of the then expected gas production for such future periods. Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Costless collars set both a maximum ceiling (a sold ceiling) and a minimum floor (a bought floor) future price. Three-way costless collars are similar to regular costless collars except that, in order to increase the ceiling price, we agree to limit the amount of the floor price protection (through a sold floor) to a predetermined amount, generally between $2.00 and $3.00 per MMBtu below the bought floor. We have accounted for these transactions using the mark-to-market accounting method. Generally, we incur accounting losses on derivatives during periods where prices are rising and gains during periods where prices are falling which may cause significant fluctuations in our Consolidated Balance Sheets (Unaudited) and Consolidated Statements of Operations (Unaudited).

Commodity Price Risk and Related Hedging Activities

At September 30, 2010, we had the following natural gas collar positions:


Period	Volume (MMBtu)		Sold Ceiling		Bought Floor		Sold Floor		Fair Value
October 2010		124,000	$	6.80	$	5.50	$	3.50	$	206,208
October 2010		124,000	$	6.35	$	5.50		—		206,208
November 2010 through March 2011		604,000	$	7.45	$	6.50		—		1,409,114

		852,000							$	1,821,530

At September 30, 2010, we had the following natural gas swap positions:


Period	Volume (MMBtu)		Price		Fair Value
October 2010		124,000	$	5.70	$	230,387
October 2010		93,000	$	6.30		228,589
November 2010 through March 2011		604,000	$	6.67		1,506,454
November 2010 through March 2011		906,000	$	7.27		2,798,614
April 2011 through October 2011		856,000	$	6.37		1,698,989
April 2011 through October 2011		856,000	$	5.37		844,155
April 2011 through October 2011		856,000	$	5.43		899,443
November 2011 through March 2012		608,000	$	7.12		1,224,339
November 2011 through March 2012		608,000	$	6.12		620,276
April 2012 through October 2012		856,000	$	5.73		665,528
November 2012 through March 2013		604,000	$	6.42		550,760

		6,971,000			$	11,267,534

Interest Rate Risks and Related Hedging Activities

interest on the underlying debt is converted to a fixed interest rate. Changes in derivative fair values that are designated as cash flow hedges are deferred as other comprehensive income or loss to the extent that they are effective and then recognized in earnings when the hedged transactions occur.


Description	Effective date		Designated maturity date		Fixed rate (1)			Notional amount		Fair Value
Floating-to-fixed swap		12/14/2007		12/14/2010		3.86	%	$	15,000,000	$	(133,898	)
Floating-to-fixed swap		1/6/2009		1/6/2011		1.38	%	$	5,000,000		(17,662	)

								$	20,000,000	$	(151,560	)

(1)	The floating rate paid by the counterparty is the British Bankers’ Association LIBOR rate.

Capital Expenditures and Capital Resources

The following table is a summary of our capital expenditures on an accrual basis by category:


	Three Months Ended September 30,				Nine months Ended September 30,
	2010		2009		2010		2009
Capital expenditures:
Leasehold acquisition	$	155,708	$	132,270	$	349,436	$	1,087,887
Exploration		—		3,720		3,115		25,597
Development		3,127,937		1,666,250		7,378,918		5,168,326
Other items (primarily capitalized overhead and interest)		270,067		439,376		659,729		1,449,686

Total capital expenditures	$	3,553,712	$	2,241,616	$	8,391,198	$	7,731,496

We expect our capital expenditures for 2010 to be $13.1 million and expect to fund such expenditures from our operating cash flows. If our operating cash flows are not sufficient to fund our planned capital expenditures, we expect to reduce our capital expenditures accordingly.

The development of coalbed methane fields requires substantial initial investment before meaningful production and resulting cash flows are realized. Among the factors that can be expected to affect our cash flows and liquidity are the physical characteristics and location of the field, the amount of water produced, the methods utilized to dispose of produced water, the transportation alternatives, and the timing and volume of initial and subsequent natural gas production.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit worthiness. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, reduce our cash flows available for drilling and place us at a competitive disadvantage. Disruptions and volatility in the global financial markets may lead to increases in the cost of capital or a contraction in credit availability impacting our ability to finance our operations and to collect trade receivables. We may require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned operating results.

Changes in natural gas prices significantly affect our revenues, financial condition, cash flows and borrowing capacity. Markets for natural gas have historically been volatile and we expect this trend to continue. Prices for natural gas may fluctuate in response to changes in supply and demand, market uncertainty, seasonal, political and other factors beyond our control. We are unable to accurately predict the prices we will receive for our natural gas. Accordingly, any significant or sustained declines in natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower natural gas prices also may reduce the amount of natural gas that we can produce economically. A decline in natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Our capital expenditure budgets are highly dependent on future natural gas prices.

Beginning in early 2009, we began implementing countermeasures in response to the above referenced trends in order to enhance our ability to execute our business strategy. These countermeasures included reducing costs, increasing hedging to reduce

exposure to volatile natural gas prices and limiting capital spending to internally generated cash flows. We currently believe that our cash flow from operations and other financial resources such as borrowings under our revolving credit facility will provide us with sufficient capital resources to develop our existing properties.

Revolving Credit Facility

Contractual Commitments

We have numerous contractual commitments in the ordinary course of business, debt service requirements and operating lease commitments. There has been no material changes in those commitments disclosed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Commitments” of our Annual Report on Form 10-K, as amended, for the year ended December 31, 2009.

Recent Pronouncements

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk. Our major commodity price risk exposure is to the prices received for our natural gas production. Realized commodity prices received for our production are the spot prices applicable to natural gas. Prices received for natural gas are volatile and unpredictable and are beyond our control. For the three months ended September 30, 2010, a 10% decrease in the prices received for natural gas production would have had an approximate $0.82 million impact on our revenues, which would have been offset by approximately $0.58 million realized gas hedging gains. For the nine months ended September 30, 2010, a 10% decrease in the prices received for natural gas production would have had an approximate $2.58 million impact on our revenues, which would have been offset by approximately $1.29 million realized gas hedging gains.

Interest Rate Risk. We have long-term debt subject to the risk of loss associated with movements in interest rates. As of September 30, 2010, we had $79.5 million of borrowings outstanding under our revolving credit facility, resulting in a borrowing availability of $10.5 million under our $90.0 million borrowing base. The rates at September 30, 2010 and December 31, 2009, excluding the effect of our interest rate swaps, were 3.59% and 3.03%, respectively. For the three months ended September 30, 2010 and 2009, interest on the borrowings averaged 4.06% per annum and 3.29% per annum, respectively. For the nine months ended September 30, 2010 and 2009, interest on the borrowings averaged 3.69% per annum and 3.09% per annum, respectively. Borrowing availability at September 30, 2010 was $10.5 million. All of the debt outstanding under our revolving credit facility accrues interest at floating or market rates. Fluctuations in market interest rates will cause our interest costs to fluctuate. Based upon the balance outstanding under our revolving credit facility at September 30, 2010, a 1% increase in market interest rates would have increased interest expense and negatively impacted our annual cash flows by approximately $0.60 million. $20 million of the outstanding balance was excluded from our market rate analysis due to lack of interest rate exposure based on the interest rate swaps we have in place.

Foreign Currency Exchange Rate Risk. We have operations in Canada and do not have operations in any other foreign countries. We do not hedge our foreign currency risk and are exposed to foreign currency exchange rate risk in the Canadian dollar. Our Canadian prospect is temporarily shut in and, therefore, the impact on our Consolidated Financial Statements (Unaudited) is not significant. We will continue to monitor the foreign currency exchange rate in Canada and may implement measures to protect against the foreign currency exchange rate risk in the future.

Item 4.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rules 13a-15(e) and 15d-15(e), we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2010 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1.

Legal Proceedings

Please see the legal proceedings described in our Quarterly Reports on Form 10-Q for the periods ended March 31, 2010 and June 30, 2010 and in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009. There were no material changes to legal proceedings during the quarter ended September 30, 2010.

Environmental and Regulatory

As of September 30, 2010, there were no known environmental or other regulatory matters related to our operations that are reasonably expected to result in a material liability to us.

Item 1A.

Risk Factors

There have been the following updates to the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K, as amended, for the year ended December 31, 2009.

We may not be able to maintain compliance with NASDAQ’s continued listing requirements.

We must comply with NASDAQ’s continued listing requirements in order to maintain our listing on NASDAQ’s Global Market. These continued listing standards include requirements addressing the number of shares publicly held, market value of publicly held shares, stockholder’s equity, number of round lot holders, and a $1.00 minimum closing bid price. On September 28, 2010, we received a deficiency letter from the staff of The NASDAQ Stock Market, advising the Company that, for the previous 30 consecutive business days, the bid price for the Company’s common stock had closed below the minimum $1.00 per share required under NASDAQ Marketplace Rule 5450(a)(1) for continued listing on the NASDAQ Global Market. The notification letter states that the Company will be afforded 180 calendar days to regain compliance with the minimum bid price requirement. In order to regain compliance, the bid price of the Company’s common stock must close at $1.00 per share or more for a minimum of ten consecutive business days.

The delisting of our common stock would adversely affect the market liquidity for our common stock, the per share price of our common stock and impair our ability to raise capital that may be needed for future operations. Delisting from NASDAQ could also have other negative results, including the potential loss of confidence by customers and employees, the loss of institutional investor interest and fewer business development opportunities. In addition, we would be subject to a number of restrictions regarding the registration and qualification of our common stock under federal and state securities laws.

If our common stock is not eligible for quotation on another market or exchange, trading of our common stock could be conducted in the over-the-counter market or on an electronic bulletin board established for unlisted securities such as the Pink Sheets or the OTC Bulletin Board. In such event, it could become more difficult to dispose of, or obtain accurate quotations for the price of our common stock, and there would likely also be a reduction in our coverage by security analysts and the news media, which could cause the price of our common stock to decline further.

We have indebtedness, which makes us more vulnerable to economic downturns and adverse developments in our business.

We have incurred bank debt amounting to approximately $79.5 million as of September 30, 2010. As a result of our indebtedness, we must use a portion of our cash flow to pay interest, which reduces the amount we have available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate. Our indebtedness under our revolving credit facility is at a variable interest rate. As such, an increase in interest rates will generate greater interest expense. The amount of our debt makes us more vulnerable to economic downturns and adverse developments in our business.

The proposed United States federal budgets for fiscal years 2010 and 2011 and other pending legislation contain certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.

In February 2009, the Obama administration released its budget proposals for the fiscal year 2010, which included numerous proposed tax changes. In April 2009, legislation was introduced to further these objectives and in February 2010, the Obama

administration released similar budget proposals for the fiscal year 2011. The proposed budget and legislation would repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies and impose new taxes. Among others, the provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical amortization period for independent producers; and implementation of a fee on non-producing leases located on federal lands. Should some or all of these provisions become law our taxes could increase, potentially significantly, after net operating losses are exhausted, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities. Although these proposals initially were made approximately one year ago, none have been voted on or become law. However, it is still the Obama administration’s stated intention to enact these provisions in 2010. We do not know the ultimate impact these proposed changes may have on our business, financial condition or results of operation.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business.

The United States Congress has passed, and the President has signed into law, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”). The Act provides for new statutory and regulatory requirements for derivative transactions, including oil and gas hedging transactions. Certain transactions will be required to be cleared on exchanges, and cash collateral will be required for these transactions. The Act provides for a potential exception from these clearing and cash collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and to the parties to those transactions. The Act requires the Commodities Futures and Trading Commission (the “CFTC”) to promulgate rules to define these terms in detail, but we do not know the definitions that the CFTC will actually promulgate or how these definitions will apply to us.

We enter into natural gas derivative contracts from time to time with respect to a portion of our expected production of natural gas in order to hedge against commodity price uncertainty and enhance the predictability of cash flows from the sale of our production. Depending on the rules and definitions adopted by the CFTC, we might in the future be required to provide cash collateral for our commodities hedging transactions. Posting of cash collateral could cause significant liquidity issues for us by reducing our ability to use our cash for capital expenditures or other corporate purposes. A requirement to post cash collateral could therefore significantly reduce our ability to execute strategic hedges to reduce commodity price uncertainty and thus protect cash flows. We are at risk unless and until the CFTC adopts rules and definitions that confirm that companies such as ourselves are not required to post cash collateral for our derivative hedging contracts. In addition, even if we ourselves are not required to post cash collateral for our derivative contracts, the banks and other derivatives dealers who are our contractual counterparties will be required to comply with the Act’s new requirements, and the costs of their compliance will likely be passed on to customers such as ourselves, thus decreasing the benefits to us of hedging transactions and reducing our profitability.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Congress is currently considering legislation to amend the federal Safe Drinking Water Act (SDWA) to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. We employ hydraulic fracturing techniques in all of the wells we drill. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. These bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. In addition, in March 2010, the EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. Thus, even if the pending bills are not adopted, the EPA study, depending on its results, could spur further initiatives to regulate hydraulic fracturing under the SDWA.

We may face unanticipated water disposal costs.

Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies or our wells produce water in excess of the applicable volumetric permit limit, we may have to shut in wells, reduce drilling activities, or upgrade facilities. The costs to dispose of this produced water may increase if any of the following occur:

•

we cannot obtain future permits from applicable regulatory agencies;

•

water of lesser quality is produced;

•

our wells produce excess water; or

•

new laws and regulations require water to be disposed of in a different manner.

All National Pollutant Discharge Elimination System (“NPDES”) permits for the discharge of produced water from coalbed methane fields in Alabama are issued for five-year terms by the Alabama Department of Environmental Management (“ADEM”) and are subject to renewal every five years. We were granted an NPDES permit for the discharge of produced water from the Gurnee field into the Black Warrior River in 2004. We have submitted a timely and complete renewal application to ADEM for a five-year renewal of our NPDES permit. No five-year renewal NPDES permits for the discharge of produced water from coalbed methane fields into streams or rivers have been granted by ADEM since our renewal application was submitted. ADEM is currently administratively extending all existing NPDES permits for disposal of produced water from coalbed methane fields into streams or rivers for which timely and complete renewal applications are received, including our NPDES permit.

Our net operating loss carryforwards may be limited or they may expire before utilization.

As of September 30, 2010, we had U.S. federal tax net operating loss carryforwards of approximately $109.4 million, which expire at various dates from fiscal year 2022 through fiscal year 2030. The years that contributed most to our federal net operating loss carryforwards were fiscal years 2003, 2004, 2005 and 2009 at $20.5, $17.2, $22.4 and $20.4 million respectively and that portion of the losses will expire in fiscal years 2023, 2024, 2025 and 2029 respectively. These net operating loss carryforwards may be used to offset future taxable income and thereby reduce our U.S. federal income taxes otherwise payable. Section 382 of the Internal Revenue Code of 1986, as amended (“the Code”), imposes an annual limit on the ability of a corporation that undergoes an “ownership change” to use its net operating loss carry forwards to reduce its tax liability. An “ownership change” would occur if stockholders, deemed under Section 382 to own 5% or more of our capital stock by value, increase their collective ownership of the aggregate amount of our capital stock by more than 50 percentage points over a defined period of time. In the event of certain changes in our shareholder base, we may at some point in the future experience an “ownership change” as defined in Section 382 of the Code. Accordingly, our use of the net operating loss carryforwards and credit carryforwards may be limited at some point in the future by the annual limitations described in Sections 382 and 383 of the Code.

Two existing stockholders each beneficially own a significant percentage of our common stock, which could limit your ability to influence the outcome of stockholder votes.

Sherwood Energy, LLC beneficially owns approximately 26% of our common stock outstanding as of the date hereof (after giving effect to the conversion of the Series A Convertible Redeemable Preferred Stock held by Sherwood) and Yorktown Energy Partners IV, L.P. beneficially owns approximately 20% of our common stock. Additional shares of our Series A Convertible Redeemable Preferred Stock may be issued to Sherwood and our other Series A preferred stockholders as paid-in-kind dividends. In addition, two of the current members of our board of directors are appointed by Sherwood and another member of our board of directors is a member and a manager of the general partner of Yorktown. As a result, Sherwood and Yorktown have, and can be expected to have, a significant voice in our affairs, in the outcome of stockholder voting concerning the election of directors, the adoption or amendment of provisions in our charter and bylaws, the approval of mergers and other significant corporate transactions.

You may experience dilution of your ownership interests due to the future issuance of additional shares of our common stock.

We may in the future issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present common stockholders. We are currently authorized to issue 125,000,000 shares of common stock and 10,000,000 shares of preferred stock with such designations, preferences and rights as determined by our board of directors. As of the date hereof, 39,758,484 shares of common stock are outstanding, and 30,950,854 shares of common stock are issuable upon conversion of outstanding Series A Convertible Redeemable Preferred Stock. An additional 3,378,221 shares, net of accrued PIK dividends, of our Series A preferred stock, convertible into 25,986,316 shares of common stock, are reserved for issuance and some or all of that amount may be issued to our preferred stockholders as paid-in-kind, or PIK, dividends. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock. We may also issue additional shares of our common stock or other securities that are convertible into or

exercisable for common stock in connection with the hiring of personnel, future acquisitions, future private placements of our securities for capital raising purposes, or for other business purposes. Any such issuance would further dilute the interests of our existing common stockholders.

Future sales of our common stock by our existing stockholders may depress our stock price.

As of September 30, 2010, 39,758,484 shares of our common stock were outstanding, together with outstanding options representing the right to purchase up to 2,796,073 shares. On September 14, 2010, we issued and sold 2,351,801 shares of our Series A Convertible Redeemable Preferred Stock to Sherwood Energy, LLC and agreed to register the shares of underlying common stock, presently 18,090,776 shares, for resale. In addition, on September 14, 2010 we issued and sold 1,648,199 shares of our Series A Convertible Redeemable Preferred Stock to participants in a registered rights offering. As of the date hereof, our outstanding Series A Convertible Redeemable Preferred Stock is convertible into an aggregate of 30,950,854 shares of our common stock, which represents approximately 77% of our issued and outstanding common stock as of the date hereof. Upon the effectiveness the resale registration statement relating to the common stock underlying shares of Series A Convertible Redeemable Preferred Stock held by Sherwood, much of the common stock underlying the Series A preferred stock may be sold by the selling security holders in market transactions from time to time. Sales of a substantial number of shares of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline.

Natural gas prices are volatile, and a decline primarily in natural gas prices would significantly affect our financial results and impede our growth.

Our revenue, profitability, and cash flow depend upon the prices and demand for natural gas. The market for natural gas is very volatile and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in natural gas prices have a significant impact on the value of our reserves and on our cash flow. Prices for natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

•

the domestic and foreign supply of natural gas;

•

the price of foreign imports;

•

overall domestic and global economic conditions;

•

the consumption pattern of industrial consumers, electricity generators, and residential users;

•

weather conditions;

•

technological advances affecting energy consumption;

•

domestic and foreign governmental regulations;

•

proximity and capacity of gas pipelines and other transportation facilities; and

•

the price and availability of alternative fuels.

Many of these factors are beyond our control. Because all of our estimated proved reserves as of December 31, 2009 were natural gas reserves, our financial results are sensitive to movements in natural gas prices. Recent natural gas prices have been extremely volatile and we expect this volatility to continue. For example, during 2009 natural gas prices declined to less than $3.00 per Mcf, the lowest level since 2002, before recovering later that year. The Henry Hub spot price for natural gas at December 31, 2009 was $5.79 per Mcf and declined to $3.36 at October 31, 2010.

The results of increased investment in the exploration for and production of gas and oil and other factors, such as global economic and financial conditions discussed below, may cause the price of gas to fall. Lower natural gas prices may not only decrease our revenues on a per Mcf basis, but also may reduce the amount of natural gas that we can produce economically. This may result in substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition, results of operations and cash flow. If there are substantial downward adjustments to our estimated proved reserves or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carry amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

If natural gas prices decline further or remain low for an extended period of time, we may, among other things, be unable to maintain our borrowing capacity or extend the maturity of our revolving credit facility, repay current or future indebtedness or obtain additional capital on satisfactory terms, all of which could adversely affect the value of our common stock.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

[Removed and Reserved]

Item 5.

Other Information

On November 5, 2010, the Company entered into the Second Amendment to Investment Agreement (the “Second Amendment”) with Sherwood Energy, LLC, which amended a provision of the Investment Agreement between the Company and Sherwood dated June 2, 2010 and amended on September 3, 2010. The Second Amendment extends the period of time permitted for the Company to file a registration statement with the SEC registering for resale the shares of our Series A Convertible Redeemable Preferred Stock held by Sherwood Energy, LLC, as well as the shares of our common stock that are issuable upon the conversion of shares of the Preferred Stock held by Sherwood. Under the terms of the Second Amendment, the time requirement has been extended from 60 business days to 180 business days. A copy of the Amendment is filed with this quarterly report as Exhibit 10.2.

Item 6.

Exhibits

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10-Q.

SIGNATURES

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


	GeoMet, Inc.

Date: November 10, 2010	By	/S/ WILLIAM C. RANKIN
		William C. Rankin, Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

INDEX TO EXHIBITS


Exhibit Number		Exhibits

3.1		Amended and Restated Bylaws of GeoMet, Inc. (Adopted as of September 14, 2010) (incorporated herein by reference to Exhibit 3.1 of the Company’s Form 8-K filed on September 20, 2010).

3.2		Certificate of Designations of Series A Convertible Redeemable Preferred Stock, par value $0.001 per share, of GeoMet, Inc. (incorporated herein by reference to Appendix B to the Company’s Definitive Proxy Statement on Schedule 14A filed on June 24, 2010).

10.1*		GeoMet, Inc. 2006 Long-Term Incentive Plan (Amended and Restated effective September 14, 2010).

10.2*		Second Amendment to Investment Agreement dated November 5, 2010 by and between GeoMet, Inc. and Sherwood Energy, LLC.

10.3		First Amendment to Investment Agreement dated September 3, 2010 by and between GeoMet, Inc. and Sherwood Energy, LLC (incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed on September 10, 2010).

10.4		Form of Indemnification Agreement between GeoMet, Inc. and officers and directors of GeoMet, Inc. (incorporated herein by reference to Exhibit 10.2 of the Company’s Form 8-K filed on September 20, 2010).

31.1*		Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).

31.2*		Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).

32*		Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

*	Attached hereto