Edgar Filing: GeoMet, Inc.

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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 June 30, 2012

o 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		(I.R.S. Employer
incorporation or organization)		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 o 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). x Yes o 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.

Large accelerated filer o		Accelerated filer o

Non-accelerated filer o		Smaller reporting company x

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

As of August 1, 2012, 40,390,077 shares and 4,989,309 shares, respectively, of the registrant’s common stock and preferred stock, par value $0.001 per share, were outstanding.

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TABLE OF CONTENTS


Part I. Financial Information

Item 1.	Consolidated Financial Statements (Unaudited)
	Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011	3
	Consolidated Statements of Operations for the three and six months ended June 30, 2012 and 2011	4
	Consolidated Statements of Comprehensive (Loss) Income for the three and six months ended June 30, 2012 and 2011	5
	Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011	6
	Notes to Consolidated Financial Statements (Unaudited)	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32

Item 4.	Controls and Procedures	32

Part II. Other Information

Item 1.	Legal Proceedings	33

Item 1A.	Risk Factors	33

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33

Item 3.	Defaults Upon Senior Securities	33

Item 4.	Mine Safety Disclosures	33

Item 5.	Other Information	33

Item 6.	Exhibits	33

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Part I. FINANCIAL INFORMATION

Item 1. Financial Statements

GEOMET, INC. AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)

	June 30, 2012			December 31, 2011
ASSETS
Current Assets:
Cash and cash equivalents	$	5,423,504		$	457,865
Accounts receivable, net of allowance of $17,634 at June 30, 2012 and December 31, 2011	3,588,237			4,402,065
Inventory	627,353			597,197
Derivative asset—natural gas contracts	14,448,265			20,685,187
Other current assets	1,245,619			1,141,310

Total current assets	25,332,978			27,283,624

Gas properties—utilizing the full cost method of accounting:
Proved gas properties	533,954,535			561,451,504
Other property and equipment	3,724,360			3,671,123

Total property and equipment	537,678,895			565,122,627
Less accumulated depreciation, depletion, amortization and impairment of gas properties	(425,511,930		)	(388,730,093		)

Property and equipment—net	112,166,965			176,392,534

Other noncurrent assets:
Derivative asset—natural gas contracts	—			1,765,450
Deferred income taxes	3,888,373			48,171,298
Other	3,090,254			3,532,882

Total other noncurrent assets	6,978,627			53,469,630

TOTAL ASSETS	$	144,478,570		$	257,145,788

LIABILITIES, MEZZANINE AND STOCKHOLDERS’ (DEFICIT) EQUITY
Current Liabilities:
Accounts payable	$	6,754,228		$	7,500,768
Accrued liabilities	4,016,281			3,936,070
Deferred income taxes	3,888,373			4,153,099
Derivative liability—natural gas contracts	78,745			—
Asset retirement liability	—			32,028
Current portion of long-term debt	15,900,000			91,757

Total current liabilities	30,637,627			15,713,722

Long-term debt	132,700,000			158,171,662
Asset retirement liability	8,318,427			8,138,551
Derivative liability—natural gas contracts	1,823,289			—
Other long-term accrued liabilities	75,622			8,145

TOTAL LIABILITIES	173,554,965			182,032,080

Commitments and contingencies (Note 14)
Mezzanine equity:
Series A Convertible Redeemable Preferred Stock—net of offering costs of $1,660,435; redemption amount $48,381,810; $.001 par value; 7,401,832 shares authorized, 4,838,181 and 4,549,537 shares were issued and outstanding at June 30, 2012 and December 31, 2011, respectively	32,178,347			28,482,624
Stockholders’ (Deficit) Equity:
Preferred stock, $0.001 par value—2,598,168 shares authorized, none issued	—			—
Common stock, $0.001 par value—authorized 125,000,000 shares; issued and outstanding 40,390,077 and 40,010,188 at June 30, 2012 and December 31, 2011, respectively	40,390			40,010
Treasury stock—10,432 shares at June 30, 2012 and December 31, 2011	(94,424		)	(94,424		)
Paid-in capital	197,964,143			200,344,209
Accumulated other comprehensive income (loss)	36,952			(1,309,926		)
Retained deficit	(258,956,576		)	(152,104,329		)
Less notes receivable	(245,227		)	(244,456		)

Total stockholders’ (deficit) equity	(61,254,742		)	46,631,084

TOTAL LIABILITIES, MEZZANINE AND STOCKHOLDERS’ (DEFICIT) EQUITY	$	144,478,570		$	257,145,788

See accompanying Notes to Consolidated Financial Statements (Unaudited)

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GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenues:
Gas sales	$	7,711,969		$	8,330,680		$	17,855,143		$	16,181,728
Operating fees	59,446			72,914			135,211			145,686

Total revenues	7,771,415			8,403,594			17,990,354			16,327,414
Expenses:
Lease operating expense	4,491,593			2,855,821			8,933,027			5,810,951
Compression and transportation expense	2,300,765			962,354			4,540,254			1,877,064
Production taxes	364,437			365,321			834,086			687,709
Depreciation, depletion and amortization	3,290,420			1,604,380			6,920,889			3,223,798
Impairment of gas properties	42,255,847			—			58,035,288			—
General and administrative	1,366,142			1,495,413			2,668,167			2,924,558
Restructuring costs	765,233			—			765,233			—
Realized gains on derivative contracts	(5,311,266		)	(1,536,056		)	(10,104,135		)	(5,033,118		)
Unrealized losses (gains) from the change in market value of open derivative contracts	10,202,879			(197,154		)	4,978,668			2,653,014

Total operating expenses	59,726,050			5,550,079			77,571,477			12,143,976
Operating (loss) income	(51,954,635		)	2,853,515			(59,581,123		)	4,183,438
Other income (expense):
Interest income	597			4,287			4,299			8,761
Interest expense (net of amounts capitalized)	(1,268,399		)	(823,703		)	(2,544,243		)	(1,663,772		)
Other	253			(9,007		)	(4,099		)	(4,325		)

Total other income (expense):	(1,267,549		)	(828,423		)	(2,544,043		)	(1,659,336		)

(Loss) income before income taxes	(53,222,184		)	2,025,092			(62,125,166		)	2,524,102
Income tax expense	(6,250		)	(902,107		)	(44,030,700		)	(907,297		)

(Loss) income before discontinued operations	(53,228,434		)	1,122,985			(106,155,866		)	1,616,805
Discontinued operations, net of tax	(675,809		)	(51,247		)	(696,381		)	(93,988		)

Net (loss) income	$	(53,904,243	)	$	1,071,738		$	(106,852,247	)	$	1,522,817

Accretion of Series A Convertible Redeemable Preferred Stock	(470,953		)	(436,029		)	(932,969		)	(859,172		)
Paid-in-kind dividends on Series A Convertible Redeemable Preferred Stock	(619,625		)	(1,336,250		)	(1,860,345		)	(2,632,110		)
Cash dividends paid on Series A Convertible Redeemable Preferred Stock	(651		)	(664		)	(1,296		)	(1,222		)

Net loss available to common stockholders	$	(54,995,472	)	$	(701,205	)	$	(109,646,857	)	$	(1,969,687	)


Net loss per share:
Net loss per common share
Basic	$	(1.37	)	$	(0.02	)	$	(2.75	)	$	(0.05	)

Diluted	$	(1.37	)	$	(0.02	)	$	(2.75	)	$	(0.05	)

Weighted average number of common shares:
Basic	40,003,977			39,617,625			39,883,409			39,544,361

Diluted	40,003,977			39,617,625			39,883,409			39,544,361

See accompanying Notes to Consolidated Financial Statements (Unaudited)

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GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Comprehensive (Loss) Income

(Unaudited)

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
Net (loss) income	$	(53,904,243	)	$	1,071,738	$	(106,852,247	)	$	1,522,817
Gain (loss) on foreign currency translation adjustment	9,470			293		2,019			740
Unrealized gain on available for sale securities	36,952			—		36,952			—
Gain on interest rate swap	—			—		—			10,862

Other comprehensive (loss) income	$	(53,857,821	)	$	1,072,031	$	(106,813,276	)	$	1,534,419

See accompanying Notes to Consolidated Financial Statements (Unaudited)

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GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended June 30,
	2012			2011
Cash flows provided by operating activities:
Net (loss) income	$	(106,852,247	)	$	1,522,817
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:
Depreciation, depletion and amortization	6,919,168			3,254,514
Impairment of gas properties	58,035,288			—
Amortization of debt issuance costs	316,671			287,309
Deferred income tax expense	44,018,200			894,797
Unrealized losses from the change in market value of open derivative contracts	4,978,668			2,665,998
Stock-based compensation	393,536			451,853
Loss on sale of Hudson’s Hope Gas, Ltd	683,154			—
Loss on sale of other assets	5,200			12,086
Accretion expense—asset retirement obligation	391,687			270,913
Changes in operating assets and liabilities:
Accounts receivable	810,421			(66,033		)
Other assets	477,654			(219,917		)
Accounts payable	(675,844		)	(1,159,720		)
Other accrued liabilities	912,190			237,329

Net cash provided by operating activities	10,413,746			8,151,946

Cash flows provided by (used in) investing activities:
Capital expenditures	(508,657		)	(6,595,291		)
Return of original basis through the settlement of natural gas derivative contracts	4,925,738			—
Proceeds from sale of other property and equipment	3,500			—
Other assets	—			18,816

Net cash provided by (used in) investing activities	4,420,581			(6,576,475		)

Cash flows used in financing activities:
Proceeds from revolving credit facility borrowings	10,500,000			15,800,000
Payments on revolving credit facility	(19,800,000		)	(16,900,000		)
Proceeds from exercise of stock options	—			3,791
Deferred financing costs	(403,383		)	(142,153		)
Payments on other debt	(167,087		)	(89,907		)
Purchase and cancellation of treasury stock	(2,037		)	(2,145		)
Cash dividends paid on Series A Convertible Redeemable Preferred Stock	(1,296		)	(1,222		)

Net cash used in financing activities	(9,873,803		)	(1,331,636		)
Effect of exchange rate changes on cash	5,115			3,409

Increase in cash and cash equivalents	4,965,639			247,244
Cash and cash equivalents at beginning of period	457,865			536,533

Cash and cash equivalents at end of period	$	5,423,504		$	783,777

Supplemental disclosure of cash flow information:
Cash paid during the period for interest expense	$	2,509,404		$	1,714,434

Cash paid during the period for income taxes	$	12,500		$	12,500

Significant noncash investing and financing activities:
Accrued capital expenditures	$	817,015		$	2,603,369

See accompanying Notes to Consolidated Financial Statements (Unaudited)

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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 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, 2011 and the accompanying notes included in our Annual Report on Form 10-K, which we filed with the Securities and Exchange Commission (the “SEC”) on March 30, 2012.

Note 2—Liquidity and Going Concern Considerations

As previously disclosed in our Quarterly Report on Form 10-Q for the period ended March 31, 2012 (“First Quarter Report”), as of May 15, 2012, we had $148.6 million outstanding under our Fifth Amended and Restated Credit Agreement (the “Credit Agreement”). As previously disclosed, the Credit Agreement provides that the borrowing base is set at the sole discretion of our lenders in June and December of each year based, in part, on the value of our estimated reserves as determined by the lenders using natural gas prices forecasted by the lenders. As of the filing date of our First Quarter Report, we expected that, due to the decline in the bank group’s price projections, the outstanding balance under the Credit Agreement at the June determination date would exceed the new borrowing base, resulting in a borrowing base deficiency which we would not be able to cure absent reaching a new agreement. As of the filing date of our First Quarter Report, the aforementioned conditions raised substantial doubt about our ability to continue as a going concern for the twelve months ended March 31, 2013.

As expected, on June 8, 2012, our bank lending group completed its June 2012 re-determination of our borrowing base under the Credit Agreement and notified us that our new borrowing base was $115.0 million, a reduction from the previous borrowing base of $180 million. As of June 8, 2012, we had $148.6 million drawn under the Credit Agreement, which resulted in a borrowing base deficiency of $33.6 million. As a result of this borrowing base deficiency, we were no longer able to borrow under the Credit Agreement.

In response to this borrowing base deficiency, we entered into the Fourth Amendment to our Fifth Amended and Restated Credit Agreement (the “Amendment”), effective August 8, 2012. The Amendment provides for an initial conforming borrowing base of $115.0 million (“Tranche A”) with the balance then remaining in the amount of $33.6 million constituting a non-conforming tranche (“Tranche B”). We are obligated, among other things, to reduce the balance of Tranche B each month by a certain amount of our excess cash flows for the period, as defined by the Amendment. In addition, we are no longer able to borrow any additional funds under the Credit Agreement, as amended.

The borrowing base will continue to be determined as of each June and December with the next determination scheduled to be completed by December 31, 2012. This Credit Agreement, as amended, matures on April 1, 2014. We believe this amendment will allow us to continue normal production operations for at least the next twelve months and management believes we have the ability to comply with the terms of the Credit Agreement, as amended; however due to the uncertainty of natural gas prices, there are no assurances that there will not be an additional borrowing base deficiency at the December 2012 or any subsequent borrowing base redetermination, which is at the sole discretion of our lenders. For additional information related to the Credit Agreement, as amended, see Note 10—Long-Term Debt.

Note 3—Recent Pronouncements

On June 16, 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-05, Presentation of Comprehensive Income, which revises the manner in which entities present comprehensive income in their financial statements. The new guidance removes the presentation options in Accounting Standards Codification (“ASC”) 220 and requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. The ASU does not change the items that must be reported in other comprehensive income. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The Company has adopted and applied the provisions of this update for the three and six months ended June 30, 2012.

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On May 12, 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (“IFRS”). The ASU is the result of joint efforts by the FASB and IASB to develop a single, converged fair value framework—that is, converged guidance on how (not when) to measure fair value and on what disclosures to provide about fair value measurements. Thus, there are few differences between the ASU and its international counterpart, IFRS 13. While the ASU is largely consistent with existing fair value measurement principles in U.S. GAAP, it expands ASC 820’s existing disclosure requirements for fair value measurements and makes other amendments. Many of these amendments were made to eliminate unnecessary wording differences between U.S. GAAP and IFRS. However, some could change how the fair value measurement guidance in ASC 820 is applied. The ASU is effective for interim and annual periods beginning after December 15, 2011. The Company has adopted and applied the provisions of this update for the three and six months ended June 30, 2012. See disclosure provided in Note 10—Long-Term Debt and Note 12—Series A Convertible Redeemable Preferred Stock.

Note 4—Net Loss Per Common Share

Net loss per common share—basic is calculated by dividing Net loss available to common stockholders by the weighted average number of shares of common stock outstanding during the period. Net loss per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net loss available to common stockholders by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Net loss per common 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 Loss per common share is as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Net (loss) income	$	(53,904,243	)	$	1,071,738		$	(106,852,247	)	$	1,522,817

Accretion of Series A Convertible Redeemable Preferred Stock	(470,953		)	(436,029		)	(932,969		)	(859,172		)
Paid-in-kind dividends on Series A Convertible Redeemable Preferred Stock	(619,625		)	(1,336,250		)	(1,860,345		)	(2,632,110		)
Cash dividends paid on Series A Convertible Redeemable Preferred Stock	(651		)	(664		)	(1,296		)	(1,222		)

Net loss available to common stockholders	$	(54,995,472	)	$	(701,205	)	$	(109,646,857	)	$	(1,969,687	)

Net loss per share:
Net loss available to common stockholders
Basic	$	(1.37	)	$	(0.02	)	$	(2.75	)	$	(0.05	)

Diluted	$	(1.37	)	$	(0.02	)	$	(2.75	)	$	(0.05	)

Weighted average number of common shares:
Basic	40,003,977			39,617,625			39,883,409			39,544,361

Add potentially dilutive securities:
Stock options, non-vested restricted stock and non-vested restricted stock units	—			—			—			—

Diluted	40,003,977			39,617,625			39,883,409			39,544,361

Net loss per common share—diluted for the three months ended June 30, 2012 excluded the effect of outstanding exercisable options to purchase 2,490,558 shares, 164,565 weighted average restricted stock units for which common shares are distributed upon achievement of certain performance targets, 268,739 weighted average restricted shares outstanding, and 4,691,632 shares of Series A Convertible Redeemable Preferred Stock (36,089,476 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported a net loss available to common stockholders which caused the options, restricted stock units, restricted shares and preferred shares to be anti-dilutive.

Net loss per common share—diluted for the six months ended June 30, 2012 excluded the effect of outstanding exercisable options to purchase 2,490,558 shares, 198,327 restricted stock units for which common shares are distributed upon achievement of certain performance targets, 258,399 weighted average restricted shares outstanding, and 4,549,537 shares of Series A Convertible Redeemable Preferred Stock (34,996,440 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported a net loss available to common stockholders which caused the options, restricted stock units, restricted shares and preferred shares to be anti-dilutive.

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Net loss per common share—diluted for the three months ended June 30, 2011 excluded the effect of outstanding exercisable options to purchase 2,603,536 shares, 232,089 restricted stock units for which common shares are distributed upon achievement of certain performance targets, 350,906 weighted average restricted shares outstanding, and 4,278,124 shares of Series A Convertible Redeemable Preferred Stock (32,908,646 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported a net loss available to common stockholders which caused the options, restricted stock units, restricted shares and preferred shares to be anti-dilutive.

Net loss per common share—diluted for the six months ended June 30, 2011 excluded the effect of outstanding exercisable options to purchase 2,603,536 shares, 232,089 restricted stock units for which common shares are distributed upon achievement of certain performance targets, 366,975 weighted average restricted shares outstanding, and 4,148,538 shares of Series A Convertible Redeemable Preferred Stock (31,911,830 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported a net loss available to common stockholders which caused the options, restricted stock units, restricted shares and preferred shares to be anti-dilutive.

Note 5—Discontinued Operations

On June 20, 2012, we sold Hudson’s Hope Gas, Ltd., a subsidiary which held our Canadian gas properties, in exchange for two million shares of Canada Energy Partners, Inc. (“CEP shares”) which we are restricted to sell for one year. We recognized a loss on the sale in the amount of $0.7 million, which was made up of a $1.3 million loss related to the currency translation adjustment, offset by $0.3 million in asset retirement liabilities conveyed to the buyer and the proceeds consisting of the $0.3 million in fair value of the CEP shares received. The loss on the sale has been included in Discontinued operations, net of tax in the Consolidated Statements of Operations (Unaudited). Additionally, all historical operating results related to the disposed company have been removed from Operating (loss) income and included in Discontinued operations, net of tax in the Consolidated Statements of Operations (Unaudited) for all periods presented.

As a result of the sale, we are treating these activities as a discontinued operation for all the periods presented. Results for activities reported as discontinued operations were as follows:

Statements of Operations (Unaudited):

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenues	$	—		$	—		$	—		$	—
Total operating benefit (expenses)	7,426			(51,247		)	(13,123		)	(93,988		)

Operating income (loss)	7,426			(51,247		)	(13,123		)	(93,988		)
Loss on sale of Hudson’s Hope, Ltd.	(683,154		)	—			(683,154		)	—
Other income (expense)	(81		)	—			(104		)	—
Income tax expense	—			—			—			—

Net loss	$	(675,809	)	$	(51,247	)	$	(696,381	)	$	(93,988	)

Balance Sheets (Unaudited):

	June 30, 2012		December 31, 2011
ASSETS
Total current assets	$	—	$	33,474
Gas properties—utilizing the full cost method of accounting:
Proved gas properties	—		28,073,293
Less accumulated depreciation, depletion, amortization and impairment of gas properties	—		(28,073,293		)

Property and equipment—net	—		—
Total other noncurrent assets	—		2,941

TOTAL ASSETS	$	—	$	36,415

LIABILITIES, MEZZANINE AND STOCKHOLDERS’ (DEFICIT) EQUITY
Current Liabilities:
Total current liabilities	$	—	$	54,827
Asset retirement liability	—		303,169

TOTAL LIABILITIES	—		357,996
Total stockholders’ deficit	—		(321,581		)

TOTAL LIABILITIES, MEZZANINE AND STOCKHOLDERS’ (DEFICIT) EQUITY	$	—	$	36,415

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Note 6—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.

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 rates for the three and six months ended June 30, 2012 were $0.92 and $0.95 per Mcf, respectively. Depletion rates for the three and six months ended June 30, 2011 were both $0.83 per Mcf.

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, 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. 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’ (deficit) equity in the period of occurrence and typically results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date.

For the twelve months ended June 30, 2012, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $3.17 per Mcf, resulting in a natural gas price of $3.34 per Mcf when adjusted for regional price differentials. For the three and six months ended June 30, 2012, we recorded a $42.3 million and a $58.0 million write-downs, respectively, of the carrying value of our U.S. full cost pool.

Note 7—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 six months ended June 30, 2012:

Current portion of liability at January 1, 2012	$	32,028
Add: Long-term asset retirement liability at January 1, 2012	8,138,551

Asset retirement liability at January 1, 2012	8,170,579
Liabilities incurred	14,252
Liabilities conveyed to buyer of Hudson’s Hope Gas Ltd.	(345,226		)
Settlements	(158,777		)
Accretion	391,687
Revisions in estimates	241,317
Foreign currency translation	4,595

Asset retirement liability at June 30, 2012	8,318,427
Less: Current portion of liability	—

Long-term asset retirement liability	$	8,318,427

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The following table details the changes to our asset retirement liability for the six months ended June 30, 2011:

Current portion of liability at January 1, 2011	$	32,893
Add: Long-term asset retirement liability at January 1, 2011	5,465,798

Asset retirement liability at January 1, 2011	5,498,691
Liabilities incurred	19,714
Accretion	270,913
Foreign currency translation	7,723

Asset retirement liability at June 30, 2011	5,797,041
Less: Current portion of liability	(33,684		)

Long-term asset retirement liability	$	5,763,357

Note 8—Derivative Instruments and Hedging 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 up to two years or more, which increase the probability of achieving our targeted level of cash flows. We are limited by our credit facility (discussed in Note 10—Long-Term Debt ) to the amount of our natural gas derivative contracts during any period to no more than 85% 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. 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 June 30, 2012, we had the following natural gas collar positions:

Period	Volume (MMBtu)	Sold Ceiling		Bought Floor		Sold Floor	Fair Value
January 2014 through December 2015	3,650,000	$	4.30	$	3.60	—	$	(439,438	)
January 2014 through December 2015	3,650,000	$	4.20	$	3.50	—	(729,409		)

	7,300,000						$	(1,168,847	)

At June 30, 2012, we had the following natural gas swap positions:

Period	Volume (MMBtu)	Fixed Price		Fair Value
July through December 2012	276,000	$	5.11	$	592,738
July through December 2012	114,000	$	5.12	245,966
July through December 2012	526,051	$	6.85	2,044,859
July through December 2012	247,337	$	6.99	1,005,101
July through December 2012	404,093	$	7.05	1,678,083
July through October 2012	492,000	$	5.73	1,426,944
July through October 2012	984,000	$	4.94	2,072,357
July through October 2012	1,845,000	$	2.89	115,547
November 2012 through March 2013	604,000	$	6.42	1,821,273
November 2012 through March 2013	906,000	$	5.50	1,906,376
November 2012 through March 2013	4,128,000	$	3.81	796,037
November 2012 through March 2013	4,128,000	$	3.82	836,969
January 2013 through December 2013	2,190,000	$	3.60	42,024
April 2013 through December 2013	2,750,000	$	3.25	(889,214		)

	19,594,481			$	13,695,060

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At December 31, 2011, we had the following natural gas swap positions:

Period	Volume (MMBtu)	Fixed Price		Fair Value
January through March 2012	364,000	$	7.12	$	1,487,299
January through March 2012	364,000	$	6.12	1,121,787
January through March 2012	546,000	$	5.08	1,118,044
January through December 2012	552,000	$	5.11	1,028,519
January through December 2012	228,000	$	5.12	427,089
January through December 2012	1,070,715	$	6.85	3,851,739
January through December 2012	528,995	$	6.99	1,977,837
January through December 2012	859,269	$	7.05	3,239,221
July through October 2012	856,000	$	5.73	2,137,811
July through October 2012	1,712,000	$	4.94	2,923,067
November 2012 through March 2013	604,000	$	6.42	1,575,321
November 2012 through March 2013	906,000	$	5.50	1,544,680

	8,590,979			$	22,432,414

At June 30, 2012, we had the following natural gas basis swap position:

Period	Volume (MMBtu)	Fixed Basis		Fair Value
July through December 2012	276,000	$	0.04	$	20,018

At December 31, 2011, we had the following natural gas basis swap position:

Period	Volume (MMBtu)	Fixed Basis		Fair Value
July through December 2012	552,000	$	0.04	$	18,223

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 Credit Agreement and the collateral for the outstanding borrowings under our Credit 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 Credit Agreement.

The application of ASC 820-10-55, 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 derivative contracts 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 credit risk on the fair value of the assets and liabilities related to the items stated below. The consideration for discounting our counterparties’ liabilities (our assets) was based on the difference between the S&P credit rating of a comparable company to our counterparties and the 13-week Treasury bill rate, both at the reporting date. The consideration for discounting our liabilities was based on the difference between the market weighted average cost of debt capital plus a premium over the capital asset pricing model and the stated interest rates of the debt instruments included in our long-term debt.

In order to estimate the fair value of our natural gas derivative contracts, a forward 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.

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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 six months ended June 30, 2012. Based on the use of observable market inputs, we have designated these types of instruments as Level 2 for ASC 820-10-55 reporting purposes. The fair value of our derivative instruments was as follows:

	Asset Derivatives						Liability Derivatives
	June 30, 2012			December 31, 2011			June 30, 2012			December 31, 2011
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives not designated as hedging instruments under ASC 815-20-25
Interest rate swaps	Derivative asset (current)	$	—	Derivative asset (current)	$	—	Derivative liability (current)	$	—	Derivative liability (current)	$	—
Natural gas hedge positions	Derivative asset (current)	14,448,265		Derivative asset (current)	20,685,187		Derivative liability (current)	78,745		Derivative liability (current)	—
Natural gas hedge positions	Derivative asset (non-current)	—		Derivative asset (non-current)	1,765,450		Derivative liability (non-current)	1,823,289		Derivative liability (non-current)	—

Total derivatives not designated as hedging instruments under ASC 815-20-25		$	14,448,265		$	22,450,637		$	1,902,034		$	—

The following (gains) losses on our hedging instruments included in the Consolidated Statements of Operations (Unaudited) and Other Comprehensive (Loss) Income (Unaudited) (“OCI”) are as follows:

The Effect of Derivative Instruments on the Consolidated Statements of Operations (Unaudited) and

Other Comprehensive (Loss) Income (Unaudited) for the Three and Six Months Ended June 30, 2012 and 2011


		Amount of (Gain) or Loss Recognized in Income on Derivative
	Location of (Gain)	Three Months Ended						Six Months Ended
	or Loss Recognized in	June 30,						June 30,
Derivatives	Income on Derivative	2012			2011			2012			2011

Derivatives not designated as hedging instruments under ASC 815-20-25
Natural gas collar/swap positions	Realized gains on derivative contracts	$	(5,311,266	)	$	(1,536,056	)	$	(10,104,135	)	$	(5,033,118	)
Natural gas collar/swap positions	Unrealized (gains) losses from the change in market value of open derivative contracts	10,202,879			(197,154		)	4,978,668			2,653,014

Total (gain) loss		$	4,891,613		$	(1,733,210	)	$	(5,125,467	)	$	(2,380,104	)

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We had an interest rate swap mature on January 6, 2011 that had previously been designated as cash flow hedges under ASC 815-20-25. On the maturity date, a loss of $17,782 was released from Accumulated Other Comprehensive Income (Loss) in the Consolidated Balance Sheet (Unaudited) and recognized as Interest expense in the Consolidated Statements of Operations (Unaudited).

At June 30, 2012, we own two million shares of Canada Energy Partners (“CEP”), discussed in Note 5—Discontinued Operations, which we classify as available for sale and mark-to-market in Other noncurrent assets on the Consolidated Balance Sheets (Unaudited) based on the closing price of the shares on the TSX Venture Exchange on that date. Gains or losses on the shares of CEP are held in Accumulated other comprehensive income (loss), net of tax. At June 30, 2012, the value of the shares recorded in Other noncurrent assets was $330,721. The Accumulated other comprehensive income of $36,952 as of June 30, 2012 consisted entirely of unrealized gains on the CEP shares.

Accumulated other comprehensive loss of $1,309,926 as of December 31, 2011 consisted entirely of foreign currency translation adjustments.

Note 9—Restructuring Costs

We recognized pretax restructuring costs of $0.8 million during the three and six months ended June 30, 2012. Restructuring activities consist of senior management and board of director changes. The restructuring costs included cash payments to our former Chief Executive Officer (“CEO”) of $0.6 million, share-based awards conveyed to our former CEO of $0.1 million and legal and consulting services of $0.1 million.

Note 10—Long-Term Debt

On November 18, 2011, our Fifth Amended and Restated Credit Agreement (the “Credit Agreement”) with a group of six banks became effective. The Credit Agreement replaced our Fourth Amended and Restated Credit Agreement and provided for revolving credit borrowings of up to $250 million with an initial borrowing base of $180 million. Effective August 8, 2012, we entered into the Fourth Amendment (the “Amendment”) to our Credit Agreement. Borrowings under the Credit Agreement at that time totaled $148.6 million. The Amendment provides for an initial conforming borrowing base of $115.0 million (the “Tranche A Borrowing Base”) with the balance then remaining in the amount of $33.6 million constituting a non-conforming tranche (the “Tranche B Borrowing Base”). The borrowing base will be determined as of each June and December with the next determination scheduled to be completed by December 31, 2012. Upon any determination of the borrowing base, the redetermined amount of the conforming borrowing base shall constitute the new Tranche A Borrowing Base, with any decrease in the Tranche A Borrowing Base causing an automatic corresponding increase in the Tranche B Borrowing Base and any increase in the Tranche A Borrowing Base causing an automatic corresponding decrease in the Tranche B Borrowing Base. At the next borrowing base determination, the Tranche B Borrowing Base shall not increase by more than fifty percent (50%) of the amount of the principal payments made on Tranche B Loans since the prior redetermination of the borrowing base. Thereafter, at each subsequent redetermination of the borrowing base, the Tranche B Borrowing Base shall not increase by more than twenty-five percent (25%) of the amount of the principal payments made on Tranche B Loans since the prior redetermination of the borrowing base. Should a future determination of the borrowing base result in the amount of the Tranche B Loan exceeding $33.6 million, the Company has 30 days to repay such excess. The Credit Agreement, as amended, will no longer provide for loans to be available on a revolving basis up to the amount of the borrowing base. As a result, the current outstanding loans, once repaid, may not be re-borrowed by the Company. All outstanding borrowings under the Credit Agreement, as amended, are due and payable on April 1, 2014. In addition, the Amendment obligates us to reduce our borrowings under the Credit Agreement, as amended, monthly by an amount equal to our bank cash, excluding (i) outstanding checks and (ii) an amount equal to $1 million as calculated on the 24th day of each month. The Amendment provides for interest to accrue at a rate calculated, at the Company’s option, at the Adjusted Base Rate plus a margin of 2.00% on the Tranche A Loans and 4.00% on Tranche B Loans or the London Interbank Offered Rate (the “LIBOR Rate”) plus a margin of 3.00% on the Tranche A loans and 5.00% on the Tranche B Loans. 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%. The banks will be paid an additional fee based on the amount of the Tranche B Loans as follows:

Calculation Date	Fee Amount	Date Payable
11/25/2012	75 bps	12/1/2012
2/25/2013	100 bps	3/1/2013
5/25/2013	125 bps	6/1/2013
8/25/2013	150 bps	9/1/2013
11/25/2013	175 bps	12/1/2013

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All financial covenants were deleted by the Amendment and were replaced with a capital expenditure covenant (a maximum of $1.5 million in 2012 and $1.0 million in 2013) and a maximum debt covenant as follows:

Quarter Ending	Maximum Principal Outstanding
9/30/2012	$	146,200,000
12/31/2012	$	139,300,000
3/31/2013	$	136,000,000
6/30/2013	$	132,700,000
9/30/2013	$	131,500,000
12/31/2013	$	129,000,000

Deferred financing costs were $0.4 million for the three and six months ended June 30, 2012. Additionally, an amendment fee of 50 basis points on the amount of Tranche B was capitalized in Deferred financing costs in the amount of $0.2 million on August 8, 2012 in connection with the execution of the Amendment. Deferred financing costs of $2.1 million as of August 8, 2012 related to the Credit Agreement prior to the Amendment were fully amortized upon execution of the Amendment due to the significant change in the terms of the amended Credit Agreement.

As of June 30, 2012, we had $148.6 million of borrowings outstanding under our Credit Agreement. The rates at June 30, 2012 and December 31, 2011 were 3.05% and 2.84% per annum, respectively.

For the three months ended June 30, 2012 we borrowed $3.1 million and made payments of $4.0 million under the Credit Agreement. For the six months ended June 30, 2012 we borrowed $10.5 million and made payments of $19.8 million under the Credit Agreement.

For the three months ended June 30, 2011 we borrowed $8.6 million and made payments of $7.7 million under the Credit Agreement. For the six months ended June 30, 2011 we borrowed $15.8 million and made payments of $16.9 million under the Credit Agreement.

For the three months ended June 30, 2012 and 2011, interest on the borrowings averaged 2.99% and 3.39% per annum, respectively. For the six months ended June 30, 2012 and 2011, interest on the borrowings averaged 2.94% and 3.40% per annum, respectively.

The following is a summary of our long-term debt at June 30, 2012 and December 31, 2011:

	June 30, 2012			December 31, 2011
Borrowings under revolving Credit Agreement	$	148,600,000		$	157,900,000
Note payable to an individual, semi-monthly installments of $644, through September 2015, interest-bearing at 12.6% annually, unsecured	—			78,012
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	—			285,407

Total debt	148,600,000			158,263,419
Less current maturities included in current liabilities	(15,900,000		)	(91,757		)

Total long-term debt	$	132,700,000		$	158,171,662

We record our debt instruments based on contractual terms. We did not elect to apply the alternative U.S. GAAP provisions of the fair value option for recording financial assets and financial liabilities. On January 1, 2012, we adopted ASU 2011-04 “Fair Value Measurement” which requires the categorization by level of the fair value hierarchy for items not measured at fair value on our Consolidated Balance Sheets (Unaudited) but for which fair value is required to be disclosed. We measure the fair value of our debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 or 2 within the fair value hierarchy. 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 market weighted average cost of equity capital plus a premium over the capital asset pricing model and the stated interest rates of the debt instruments included in our long-term debt. The fair value of long-term debt at June 30, 2012 and December 31, 2011 was estimated to be approximately $136.1 million and $131.1 million, respectively.

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Note 11—Common Stock

At June 30, 2012 and December 31, 2011, there were 40,390,077 and 40,010,188 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 June 30, 2012 and December 31, 2011 were 275,623 and 293,166 shares of restricted stock, respectively.

On March 28, 2012 and May 11, 2012, 64,284 and 97,824 shares of common stock, respectively, were issued under the 2006 Plan to our independent directors, each representing 12.5% of their annual retainer. The compensation cost was determined using NASDAQ’s closing price of our common stock on the day of issuance.

For the three and six months ended June 30, 2012, no shares of common stock were issued upon the exercise of stock options granted under our 2006 Long-Term Incentive Plan. During the same periods, no common stock was issued upon the exercise of stock options granted under our 2005 Stock Option Plan which was terminated on March 11, 2011.

On January 5, 2011, 98,416 shares of restricted stock were granted in exchange for 566,968 options. For the details related to the “Option Exchange”, see Note 13—Share-Based Awards.

On March 24, 2011 and June 15, 2011, 819 shares and 744 shares of common stock, respectively, were purchased by us from two non-executive employees for the payment of $1,335 and $811, respectively, 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.

On April 5, 2011, we issued 113,208 shares of common stock to our independent directors, representing 50% of their 2011 annual retainer.

Note 12—Series A Convertible Redeemable Preferred Stock

At June 30, 2012 and December 31, 2011, 4,838,181 and 4,549,537 shares of preferred stock were issued and outstanding, respectively. At June 30, 2012, an additional 2,563,651 shares of our Series A Convertible Redeemable Preferred Stock (“Preferred Stock”) are reserved exclusively for the payment of paid-in-kind dividends (“PIK dividends”). We measure the fair value of PIK dividends using a discounted cash flow analysis based on our current borrowing rates (categorized as level 3).

The following table details the activity related to the Preferred Stock for the six months ended June 30, 2012:

	Dividend Period (Three Months Ended)	Date Issued	Number of Shares	Balance

Balance at December 31, 2011			4,549,537	$	28,482,624
Accretion of Preferred Stock				932,969
PIK Dividends Issued for Preferred Stock :	12/31/11	1/3/12	142,095	1,522,035
	3/31/12	4/2/12	146,549	1,240,719

Balance At June 30, 2012			4,838,181	$	32,178,347

On June 8, 2012, we declared a quarterly dividend of 151,128 shares of Preferred Stock covering the period April 1, 2012 through June 30, 2012. As those shares were not issued until July 2, 2012, they have not been included in the Preferred Stock balance at June 30, 2012. As such, we recorded a dividend payable in Current liabilities in the Consolidated Balance Sheet (Unaudited) at June 30, 2012 at an estimated fair value of $619,625. Additionally, on March 31, 2012 and June 30, 2012, cash dividends of $645 and $651, respectively, were paid for fractional share dividends not paid-in-kind.

The following table details the activity related to the Preferred Stock for the six months ended June 30, 2011:

	Dividend Period (Three Months Ended)	Date Issued	Number of Shares	Balance

Balance at December 31, 2010			4,148,538	$	22,074,320
Accretion of Preferred Stock				859,172
PIK Dividends Issued for Preferred Stock :	3/31/11	3/31/11	129,586	1,295,860
	6/30/11	6/30/11	133,625	1,336,250
Other				(128,393		)

Balance At June 30, 2011			4,411,749	$	25,437,209

Additionally, on March 31, 2011 and June 30, 2011, cash dividends of $558 and $664, respectively, were paid for fractional share dividends not paid-in-kind.

Note 13—Share-Based Awards

As of June 30, 2012, our 2006 Long-Term Incentive Plan (the “2006 Plan”) is our only authorized stock-based award plan. Our 2005 Stock Option Plan was terminated on March 11, 2011 as no options granted under the plan remained outstanding at that time. Our 2006 Plan authorizes 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 are available for grant under this plan. The 2006 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,

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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 which are granted solely 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 June 30, 2012, we recorded a compensation expense accrual of $282,350 of which $12,433 was allocated to lease operating expenses, $135,220 was allocated to general and administrative expenses, $131,127 was allocated to restructuring costs, and $3,570 was capitalized to gas properties. During the six months ended June 30, 2012, we recorded a compensation expense accrual of $414,149 of which $22,294 was allocated to lease operating expenses, $240,116 was allocated to general and administrative expenses, $131,127 was allocated to restructuring costs, and $20,612 was capitalized to gas properties. The future compensation cost of all the outstanding awards at June 30, 2012 is $473,597 which will be amortized over the vesting period of such awards. The weighted average remaining useful life of the future compensation cost is 1.02 years.

During the three months ended June 30, 2011, we recorded a compensation expense accrual of $354,287 which was allocated as an addition of $8,376 to lease operating expenses, an addition of $309,579 to general and administrative expense, and $36,332 was capitalized to unevaluated gas properties. During the six months ended June 30, 2011, we recorded a compensation expense accrual of $517,154 of which $20,163 was allocated to lease operating expenses, $431,692 was allocated to general and administrative expenses, and $65,300 was capitalized to gas properties. The weighted average remaining useful life of the future compensation cost was 1.29 years.

On May 15, 2012, 150,000 shares of restricted stock were granted to our executive officers. On March 28, 2012 and May 11, 2012, 64,284 and 97,824 shares of common stock, respectively, were issued under the 2006 Plan to our independent directors, each representing 12.5% of their annual retainer. The compensation cost was determined using NASDAQ’s closing price of our common stock on the day of issuance.

On April 5, 2011, we granted 673,551 stock options with time vesting criteria to certain key employees, including our five executive officers, 232,089 restricted stock units with performance vesting criteria to our five executive officers and 113,208 shares of common stock to our independent directors, representing 50% of their annual retainer. The significant assumptions used in determining the compensation costs included an expected volatility of 87.2%, risk-free interest rate of 2.28%, an expected term from 4.38 to 4.83 years, forfeiture rates from 5% to 15%, and no expected dividends.

Option Exchange

On December 7, 2010, we offered our eligible employees the opportunity to exchange certain outstanding stock options for new restricted shares of GeoMet common stock to be granted under the 2006 Plan (“Option Exchange”). Options eligible for exchange, or eligible options, included those options, whether vested or unvested, that met all of the following requirements:

· the options had a per share exercise price greater than $5.00;

· the options were granted under one of our existing equity incentive plans;

· the options were outstanding and unexercised as of January 5, 2010;

· the options were not granted within the twelve-month period immediately preceding the commencement of this offer, December 7, 2010; and

· the options did not have a remaining term of less than 12 months immediately following January 5, 2010.

On January 5, 2011, 98,416 shares of restricted stock were granted to those eligible employees as follows:

Exercise Price Per Share		Number of Eligible Options	Number of New Restricted Shares To Be Granted in Exchange
$	5.04	85,122	32,391
$	6.98	65,244	993
$	7.64	16,000	244
$	8.30	247,359	57,287
$	10.88	8,265	881
$	13.00	144,978	6,620

		566,968	98,416

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The Option Exchange was accounted for as a modification of an award in accordance with ASC 718-20-35-3. We recognize the incremental compensation expense of $102,348 over the remaining requisite service period. The incremental compensation expense is the excess of the fair value of the shares of restricted stock granted (using the closing market price) over the fair value of the cancelled options (using the black-scholes model) on January 5, 2011.

Incentive Stock Options

The table below summarizes incentive stock option activity for the six months ended June 30, 2012:

	Number of Options		Weighted Average Exercise Price		Average Remaining Contractual Life	Aggregate Intrinsic Value
Outstanding at December 31, 2011	1,574,886		$	1.11
Forfeited	(76,600	)	$	1.17

Outstanding at June 30, 2012	1,498,286		$	1.10	4.8	$	—

Options exercisable at June 30, 2012	879,601		$	1.00	4.7	$	—

The table below summarizes incentive stock option activity for the six months ended June 30, 2011:

	Number of Options		Weighted Average Exercise Price		Average Remaining Contractual Life	Aggregate Intrinsic Value
Outstanding at December 31, 2010	1,391,611		$	2.85
Exchanged in Option Exchange	(328,220	)	$	8.41
Granted	593,079		$	1.59
Exercised	(5,265	)	$	0.72
Forfeited	(39,941	)	$	9.24

Outstanding at June 30, 2011	1,611,264		$	1.10	3.6	$	873,276

Options exercisable at June 30, 2011	278,324		$	0.72	4.7	$	256,058

During the three and six months ended June 30, 2011, 3,333 and 5,265 incentive stock options, respectively, were exercised with an intrinsic value of $2,266 and $3,793, respectively.

Non-Qualified Stock Options

The table below summarizes non-qualified stock option activity for the six months ended June 30, 2012:

	Number of Options	Weighted Average Exercise Price		Average Remaining Contractual Life	Aggregate Intrinsic Value
Outstanding at December 31, 2011	992,272	$	2.32

Outstanding at June 30, 2012	992,272	$	2.32	1.9	$	—

Options exercisable at June 30, 2012	935,242	$	2.42	1.8	$	—

The table below summarizes non-qualified stock option activity for the six months ended June 30, 2011:

	Number of Options		Weighted Average Exercise Price		Average Remaining Contractual Life	Aggregate Intrinsic Value
Outstanding at December 31, 2010	1,150,548		$	3.87
Exchanged in Option Exchange	(238,748	)	$	9.52
Granted	80,472		$	1.59

Outstanding at June 30, 2011	992,272		$	2.32	2.9	$	99,520

Options exercisable at June 30, 2011	808,000		$	2.60	2.3	$	—

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Restricted Stock Awards

The table below summarizes non-vested restricted stock awards activity for the six months ended June 30, 2012:

	Number of Shares		Weighted Average Value at Grant Date
Non-vested restricted stock at December 31, 2011	293,166		$	3.03
Granted	150,000		$	0.43
Vested	(138,615	)	$	1.32
Forfeited	(28,928	)	$	3.77

Non-vested restricted stock at June 30, 2012	275,623		$	2.40

During the three and six months ended June 30, 2012, 107,182 shares and 138,615 shares of restricted stock, respectively, vested with a weighted average vesting date fair value of $0.52 and $0.61 per share, respectively.

The table below summarizes non-vested restricted stock awards activity for the six months ended June 30, 2011:

	Number of Shares		Weighted Average Value at Grant Date
Non-vested restricted stock at December 31, 2010	292,512		$	3.95
Vested	(51,890	)	$	6.80
Granted in Option Exchange	98,416		$	1.32

Non-vested restricted stock at June 30, 2011	339,038		$	2.75

During the three and six months ended June 30, 2011, 14,400 and 51,890 shares of restricted stock, respectively, vested with a vesting date fair value of $1.09 and $1.48 per share, respectively.

Restricted Stock Unit Awards

On April 5, 2011, we granted 232,089 restricted stock units to our five executive officers. These restricted stock units vest upon the Company’s achievement of certain performance targets, but no earlier than ratably over the three year period following the grant date, at which time one common share will be issued and exchanged for each restricted stock unit held. The restricted stock units are included in the calculation of diluted earnings per share utilizing the treasury stock method. On April 30, 2012, 99,108 restricted stock units vested with a vesting date fair value of $0.53 per share. There have been no grants or forfeitures of restricted stock units subsequent to the aforementioned grant.

Note 14—Commitments and Contingencies

From time to time we are a party to litigation in the normal course of business. Management does not believe that the outcome of lawsuits or other proceedings against us will have an adverse effect on our financial condition, results of operations or cash flows.

Lease Revenue Audit—The lessor from one of our leases recently completed a five year revenue audit where the examiner claims to have identified an exception related to compressor fuel deductions. In May 2012, the claim was settled for $356,146, which was the amount recorded in the Consolidated Balance Sheet (Unaudited) as of March 31, 2012 and the Consolidated Statement of Operations (Unaudited) for the three months ended March 31, 2012 related to this matter.

Environmental and Regulatory

As of June 30, 2012, 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 15—Income Taxes

We record our income taxes using an asset and liability approach in accordance with the provisions of ASC 740. This results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities using enacted tax rates at the end of the period. Under ASC 740, the effect of a change in tax rates of deferred tax assets and liabilities is recognized in the year of the enacted change.

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Additionally, for tax reporting purposes, we have a federal capital loss carryforward generated by the sale of Hudson’s Hope Gas, Ltd., as described in Note 5—Discontinued Operations, of approximately $34.9 million at June 30, 2012 that is available to reduce future taxable capital gains and expiring in 2017.

In determining the carrying value of a deferred tax asset, ASC 740 provides for the weighing of all available evidence in estimating whether and how much of a deferred tax asset may be recoverable. In order to assess the realization of our net deferred tax asset as of June 30, 2012 and December 31, 2011, the Company considered all available negative and positive evidence. The Company had incurred a cumulative pre-tax loss of $140.9 million, which includes ceiling impairment charges of $156.0 million, over the three year period ended June 30, 2012. The Company evaluated all available evidence including historical operating results, historical pricing, natural gas reserves as estimated and appraised by an independent third party engineer, the forward natural gas price curve, and the length of the carryforward period available.

Our recent cumulative net losses and the forward natural gas price curve represented sufficient negative evidence to outweigh the positive evidence under the evaluation guidance of ASC 740. As a result, we established a full valuation allowance for our U.S. net deferred tax assets at March 31, 2012 of $47.3 million. For the three months ended June 30, 2012, we recorded an income tax benefit of $20.3 million related to our pretax loss of $53.9 million, for which we provided a full valuation allowance. Additionally, we generated a deferred tax asset for the capital loss recognized on the sale of Hudson’s Hope Gas, Ltd., for which we also provided a full valuation allowance, as described in Note 5—Discontinued Operations, in the amount of $13.2 million. Our valuation allowance for our net deferred tax assets as of June 30, 2012 is $80.8 million. These tax benefits will be available, prior to the expiration of carryforwards, to reduce future income tax expense resulting from earnings or increases in deferred tax liabilities.

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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,” “may,” “will,” “project,” “forecast,” “plan,” 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. Certain of these risks are summarized under “Item 1A. Risk Factors” in our 2011 Annual Report on Form 10-K that we filed with the SEC on March 30, 2012, which you should read carefully in connection with our forward-looking statements. 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, 2011, which are included in our 2011 Annual Report on Form 10-K.

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, developer and producer of coalbed methane properties since 1993. Our principal operations and producing properties are located in the Cahaba and Black Warrior Basins in Alabama and the central Appalachian Basin in Virginia and West Virginia. We also own additional coalbed methane and oil and gas development rights, principally in Alabama, Virginia, and West Virginia. As of June 30, 2012, we own a total of approximately 186,000 net acres of coalbed methane and oil and gas development rights.

The natural gas industry is capital intensive. We have historically made substantial capital expenditures in the exploration for, development and acquisition of natural gas reserves. Our capital expenditures have been financed primarily with internally generated cash from operations and proceeds from bank borrowings. The continued availability of these capital sources depends upon a number of variables, including proved reserves, production from existing wells, the sales prices for natural gas, the existence of hedging opportunities, our ability to acquire, locate and produce new reserves, and events occurring within the global capital markets.

Natural gas prices continue to adversely affect the natural gas industry and GeoMet by reducing our cash flows, capital expenditures and debt capacity. During 2011 and the first five months of 2012, prices received for natural gas in the United States continued to decline significantly which we believe, among other things, is due to over-supply, primarily from shale drilling, and reduced demand due to milder weather. On April 21, 2012, the Henry Hub spot price closed at $1.825/Mmbtu, its lowest in over 10 years. Presented below are the NYMEX Settle Prices for the period January 2012 through August 2012 and the NYMEX Forward Curve Prices (as of August 9, 2012) for natural gas for the period September 2012 through December 2013:

Liquidity and Bank Agreement

Cash flows provided by operations for the six months ended June 30, 2012 and 2011 were $10.4 million and $8.2 million, respectively. As of June 30, 2012, we had a working capital deficit of $5.3 million and, at December 31, 2011, we had working capital of $11.6 million. The working capital deficit as of June 30, 2012 was primarily the result of the classification of $15.9 million of our borrowings under the new Credit Agreement as a current liability in the Consolidated Balance Sheet (Unaudited). We believe that our cash flow from operations, as adjusted to comply with the terms of the new Credit Agreement, will provide us with sufficient capital resources to fund our working capital deficit and to meet our limited capital expenditure requirements to operate our properties effectively for at least the next twelve months.

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Should a future determination of the borrowing base result in the amount of the Tranche B Loan exceeding $33.6 million, the Company has 30 days to repay such excess. The Credit Agreement, as amended, will no longer provide for loans to be available on a revolving basis up to the amount of the borrowing base. As a result, the current outstanding loans, once repaid, may not be re-borrowed by the Company. All outstanding borrowings under the Credit Agreement, as amended, are due and payable on April 1, 2014. In addition, the Amendment obligates us to reduce our borrowings under the Credit Agreement, as amended, monthly by an amount equal to our bank cash, excluding (i) outstanding checks and (ii) an amount equal to $1 million as calculated on the 24th day of each month. The Amendment provides for interest to accrue at a rate calculated, at the Company’s option, at the Adjusted Base Rate plus a margin of 2.00% on the Tranche A Loans and 4.00% on Tranche B Loans or the London Interbank Offered Rate (the “LIBOR Rate”) plus a margin of 3.00% on the Tranche A loans and 5.00% on the Tranche B Loans. 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%. The banks will be paid an additional fee based on the amount of the Tranche B Loans as follows:

Calculation Date	Fee Amount	Date Payable
11/25/2012	75 bps	12/1/2012
2/25/2013	100 bps	3/1/2013
5/25/2013	125 bps	6/1/2013
8/25/2013	150 bps	9/1/2013
11/25/2013	175 bps	12/1/2013

Quarter Ending	Maximum Principal Outstanding
9/30/2012	$	146,200,000
12/31/2012	$	139,300,000
3/31/2013	$	136,000,000
6/30/2013	$	132,700,000
9/30/2013	$	131,500,000
12/31/2013	$	129,000,000

An amendment fee of 50 basis points on the amount of Tranche B was capitalized in Deferred financing costs in the amount of $0.2 million on August 8, 2012 in connection with the execution of the Amendment. Deferred financing costs of $2.1 million as of August 8, 2012 related to the Credit Agreement prior to the Amendment were fully amortized upon execution of the Amendment due to the significant change in the terms of the amended Credit Agreement.

Current Business Plan

Our current business plan is not significantly altered as a result of the Amendment to our Credit Agreement. Our focus remains on the reduction of costs and the optimization of production volumes to maintain maximum cash flow and liquidity. We plan to continue taking the following steps during the remainder of 2012, while remaining in accordance with the provisions of our Credit Agreement, as amended:

· limit capital spending to amounts we deem appropriate to maintain our leases and properties,

· reduce operating and administrative costs with particular attention to the properties acquired in November of 2011,

· apply excess cash flows to reduce bank debt,

· monitor the natural gas futures markets and enter into hedging transactions opportunistically, and

· seek transactional opportunities to expand our natural gas reserves in order to increase economies of scale.

In summary, the terms of the Credit Agreement, as amended, are consistent with our current business plan in that we were already applying excess cash flows to reduce bank debt, limiting our capital spending for the next two years and significantly hedged in 2012 with continued efforts to hedge natural gas prices in 2013 and 2014. In addition, we were engaged in considering transactional opportunities to expand our natural gas reserves in order to increase economies of scale.

NASDAQ Capital Market

On May 10, 2012, we received approval from NASDAQ to transfer the listing of our common stock and preferred stock from The NASDAQ Global Market to The NASDAQ Capital Market. Our common stock and preferred stock began trading on The NASDAQ Capital Market at the opening of the market on May 14, 2012. On August 3, 2012, we received a notice from NASDAQ advising us that our common stock has failed to regain compliance with the $1.00 minimum bid price requirement for continued listing on the NASDAQ Capital Market and, as a result, our common stock was delisted from the NASDAQ Capital Market at the opening of business on August 13, 2012. Our preferred stock will continue to be traded on the NASDAQ Capital Market under the symbol “GMETP”. We do not currently intend to request an appeal hearing regarding the delisting of our common stock. Our common stock now trades on the OTC Bulletin Board under the symbol “GMET”. This delisting could limit our strategic alternative described below.

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Other Developments

Management and Board of Director Changes

On April 30, 2012, J. Darby Seré resigned from the positions of Chairman of the Board, President and Chief Executive Officer of the Company. The Company and Mr. Seré entered into a separation agreement that provides for certain payments to Mr. Seré, including a lump sum payment of $499,500, $2,000 per month for 18 months and $30,000 per month as a consulting fee for up to nine months. The separation agreement further provided for certain adjustments to equity awards owned by Mr. Seré. The Board of Directors of the Company appointed Michael Y. McGovern as the Company’s Chairman of the Board; William C. Rankin, as a new Board member and as its new President and Chief Executive Officer; and Tony Oviedo, as the Company’s Senior Vice President, Chief Financial Officer, Chief Accounting Officer and Controller.

Strategic Alternatives

The Company has retained FBR Capital Markets & Co. (“FBR”) as its advisor to review strategic alternatives, primarily focused on identifying potential merger partners. The Company believes a merger transaction would be beneficial during the current natural gas price environment, allowing it to spread fixed costs over a larger production and reserve base. The Company will continue to pursue its long range plans pending identification of a suitable transaction. The initial retainer paid to FBR was $50,000 and there currently are no additional future financial commitments unless we enter into a transaction.

Ceiling Write-Down

The ceiling test is calculated using the unweighted arithmetic average of the natural gas price on the first day of each month within the twelve-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. For the twelve months ended June 30, 2012, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $3.17 per Mcf, resulting in a natural gas price of $3.34 per Mcf when adjusted for regional price differentials. Based on the ceiling test performed utilizing the aforementioned prices, we recorded a $42.3 million write-down of the carrying value of our U.S. full cost pool at June 30, 2012. We recorded a $15.8 million write-down of the carrying value of our U.S. full cost pool at March 31, 2012. Based on current forward natural gas price curve, we expect additional ceiling write-downs during 2012 which will continue to be significant to our gas properties, statements of operations and shareholders’ (deficit) equity.

Deferred Tax Asset

For tax reporting purposes, we have federal and state net operating losses (“NOL’s”) of approximately $131.9 million and $137.6 million, respectively, at June 30, 2012 that are available to reduce future taxable income. For tax reporting purposes, we had federal and state NOL’s of approximately $126.0 million and $132.3 million, respectively, at December 31, 2011 that were available to reduce future taxable income. Our first material NOL carryforward expires in 2022 and the last one expires in 2031. Additionally, for tax reporting purposes, we have federal capital loss carryforward generated by the sale of Hudson’s Hope Gas, Ltd., as described in Note 5—Discontinued Operations in the Notes to Consolidated Financial Statements (Unaudited), of approximately $34.9 million at June 30, 2012 that is available to reduce future taxable capital gains and expiring in 2017.

Our recent cumulative net losses and the forward natural gas price curve represented sufficient negative evidence to outweigh the positive evidence under the evaluation guidance of ASC 740. As a result, we established a full valuation allowance for our U.S. net deferred tax assets at March 31, 2012 of $47.3 million. For the three months ended June 30, 2012, we recorded an income tax benefit of $20.3 million related to our pretax loss of $53.9 million, for which we provided a full valuation allowance. Additionally, we generated a deferred tax asset for the capital loss recognized on the sale of Hudson’s Hope Gas, Ltd., for which we also provided a full valuation allowance, as described in Note 5—Discontinued Operations in the Notes to Consolidated Financial Statements (Unaudited), in the amount of $13.2 million. Our valuation allowance for our net deferred tax assets as of June 30, 2012 is $80.8 million. These tax benefits will be available, prior to the expiration of carryforwards, to reduce future income tax expense resulting from earnings or increases in deferred tax liabilities.

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Operational Update

Our core areas of operations are in the Central Appalachian Basin of Virginia and West Virginia and the Black Warrior and Cahaba Basins in Alabama. The Central Appalachian Basin is a mountainous region where coal mining is prevalent. The Black Warrior and Cahaba Basins are hilly, gently rolling regions and coal mining is also present but less active.

Peace River - On June 20, 2012, we sold Hudson’s Hope Gas, Ltd., which held our Canadian gas properties, in exchange for two million shares of Canada Energy Partners, Inc. which we are restricted to sell for one year. In connection with the sale we recognized a non-cash loss of $0.7 million; however, this disposition will reduce our cash flow losses and future obligations such as plugging and abandonment.

Central Appalachia - In the Central Appalachian Basin, we are the operator of 300 vertical wells in which we own a 99.0% average working interest. Additionally, we are the operator of 86 horizontal wells in which we own a 66.0% average working interest. We also have a 34.0% average working interest in 64 non-operated horizontal wells. Three properties with 23 net wells averaging 500 Mcf/day total net sales were shut —in on June 14, 2012. These wells were generating negative cash flows due to low gas prices and declining production. We are currently evaluating proposals from other parties to acquire the shut —in properties which would reduce our future obligations. We will continue to evaluate other properties which may result in further shut-ins due to negative cash flows. In Central Appalachia, we are party to six firm transportation agreements with total maximum daily quantities of approximately 54,000 MMBtu per day and primary terms expiring from April 2012 through November 2024 which can be automatically extended from time to time at the maximum tariff rate. In some cases, our gas sales volumes are delivered to market under transportation agreements controlled by our working interest partners. Generally, our gas sales volumes are sold at a delivery point into the respective interstate pipeline system utilized.

Black Warrior and Cahaba Basins - In the Cahaba Basin in Alabama, we are the operator of 252 vertical wells for which we own a 100.0% working interest. Our gas sales volumes from the Cahaba Basin are delivered and sold into the Southern Natural Gas pipeline system. In the Black Warrior Basin, we own working, overriding royalty or royalty interests in 938 non-operated vertical wells. Of these non-operated vertical wells, we own an average working interest of 15% in 476 wells, and we own an average royalty or overriding royalty interest of 8.57% in the remaining 462 wells. Our gas sales volumes from the Black Warrior Basin are delivered and sold into the Southern Natural Gas pipeline system under transportation arrangements controlled by the operators of the properties.

In accordance with our business plan described above, we have not drilled any new wells to date and we have continued to reduce operating expenses and apply the majority of our cash flows to the reduction of bank debt. If no new wells are drilled, we expect net gas sales to decline during 2012 by approximately 3% to 8% from year end levels.

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 have been no significant changes to our critical accounting policies during the six months ended June 30, 2012.

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Natural Gas Production Operations Summary

The table below presents information on gas sales, net sales volumes, production expenses and per Mcf data for the three and six months ended June 30, 2012 and 2011. This table should be read in conjunction with the discussion of the results of operations for the periods presented below (in thousands, except per Mcf amounts).

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011

Gas sales (1)	$	7,712	$	8,331	$	17,855	$	16,182

Lease operating expenses	$	4,492	$	2,856	$	8,933	$	5,811
Compression and transportation expenses	2,301		962		4,540		1,877
Production taxes	364		365		834		688

Total production expenses	$	7,157	$	4,183	$	14,307	$	8,376

Net sales volumes (Consolidated) (MMcf)	3,448		1,840		7,078		3,679
Pond Creek field (Central Appalachian Basin) (MMcf)	1,459		1,347		2,925		2,709
Other Central Appalachian Basin fields (MMcf)	996		49		2,045		87
Gurnee field (Cahaba Basin) (MMcf)	438		441		895		877
Black Warrior Basin fields (MMcf)	555		3		1,213		6

Per Mcf data ($/Mcf):

Average natural gas sales price realized (Consolidated)(2)	$	3.78	$	5.36	$	3.95	$	5.77

Average natural gas sales price (Consolidated)	$	2.24	$	4.53	$	2.52	$	4.40
Pond Creek field (Central Appalachian Basin)	$	2.26	$	4.58	$	2.61	$	4.43
Other Central Appalachian Basin fields	$	2.14	$	4.41	$	2.38	$	4.31
Gurnee field (Cahaba Basin)	$	2.25	$	4.40	$	2.52	$	4.30
Black Warrior Basin fields	$	2.32	$	4.23	$	2.56	$	4.23

Lease operating expenses (Consolidated)	$	1.29	$	1.57	$	1.26	$	1.59
Pond Creek field (Central Appalachian Basin)	$	1.05	$	1.14	$	1.04	$	1.19
Other Central Appalachian Basin fields	$	1.41	$	1.63	$	1.42	$	1.57
Gurnee field (Cahaba Basin)	$	2.75	$	2.72	$	2.60	$	2.73
Black Warrior Basin fields	$	0.59	$	0.00	$	0.52	$	0.02
Compression and transportation expenses (Consolidated)	$	0.67	$	0.52	$	0.64	$	0.51
Pond Creek field (Central Appalachian Basin)	$	0.64	$	0.55	$	0.58	$	0.54
Other Central Appalachian Basin fields	$	1.14	$	0.89	$	1.16	$	1.07
Gurnee field (Cahaba Basin)	$	0.23	$	0.38	$	0.26	$	0.35
Black Warrior Basin fields	$	0.21	$	0.04	$	0.19	$	0.04
Production taxes (Consolidated)	$	0.10	$	0.20	$	0.12	$	0.19
Pond Creek field (Central Appalachian Basin)	$	0.13	$	0.20	$	0.15	$	0.18
Other Central Appalachian Basin fields	$	0.06	$	0.00	$	0.06	$	0.00
Gurnee field (Cahaba Basin)	$	0.09	$	0.22	$	0.10	$	0.21
Black Warrior Basin fields	$	0.14	$	0.24	$	0.15	$	0.25
Total production expenses (Consolidated)	$	2.06	$	2.29	$	2.02	$	2.29
Pond Creek field (Central Appalachian Basin)	$	1.82	$	1.89	$	1.77	$	1.91
Other Central Appalachian Basin fields	$	2.61	$	2.52	$	2.64	$	2.64
Gurnee field (Cahaba Basin)	$	3.07	$	3.32	$	2.96	$	3.29
Black Warrior Basin fields	$	0.94	$	0.28	$	0.86	$	0.31
Depletion (Consolidated)	$	0.92	$	0.83	$	0.95	$	0.83

(1) Gas sales do not include realized gains and losses on derivative contracts.

(2) Average realized price includes the effects of realized gains and losses on derivative contracts.

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Results of Operations

Three months ended June 30, 2012 compared with three months ended June 30, 2011

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

	Three Months Ended June 30,
	2012			2011			Change
	(In thousands)
Gas sales	$	7,712		$	8,331		-7	%
Lease operating expenses	$	4,492		$	2,856		57	%
Compression expense	$	1,256		$	640		96	%
Transportation expense	$	1,045		$	322		225	%
Production taxes	$	364		$	365		0	%
Depreciation, depletion and amortization	$	3,290		$	1,604		105	%
Impairment of gas properties	$	42,256		$	—		NM
General and administrative	$	1,366		$	1,495		-9	%
Restructuring costs	$	765		$	—		NM
Realized gains on derivative contracts	$	(5,311	)	$	(1,536	)	246	%
Unrealized losses (gains) from the change in market value of open derivative contracts	$	10,203		$	(197	)	NM
Interest expense, net of amounts capitalized	$	1,268		$	824		54	%
Income tax expense	$	6		$	902		-99	%
Discontinued operations	$	676		$	51		NM

NM-Not Meaningful

Gas sales. Gas sales decreased by $0.6 million, or 7%, to $7.7 million compared to the prior year quarter. The decrease in gas sales was primarily the result of a 51% decrease in natural gas prices, excluding hedging transactions, partially offset by higher production volumes, of which 1.5 Bcf was due to our November 18, 2011 acquisition of coalbed methane gas properties, while 0.1 Bcf was due to increased production in our previously existing properties.

Lease operating expenses. Lease operating expenses increased by $1.6 million, or 57%, to $4.5 million compared to the prior year quarter. The $1.6 million increase in lease operating expenses consisted of $1.7 million increase due to our recent acquisition of coalbed methane gas properties partially offset by a $0.1 million decrease in our previously existing properties.

Compression expense. Compression expense increased by $0.6 million, or 96%, to $1.3 million compared to the prior year quarter. The increase was primarily attributable to the $0.4 million of expenses related to our recently purchased gas properties combined with an increase of $0.2 million related to our previously existing properties. The increase in compression expenses in our previously existing properties was due to increased production.

Transportation expense. Transportation expense increased by $0.7 million, or 225%, to $1.0 million compared to the prior year quarter. The increase was due to the recent acquisition of coalbed methane gas properties. Transportation expenses remained relatively flat in our previously existing gas properties.

Production taxes. Production taxes remained relatively flat compared to the prior year quarter.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $1.7 million, or 105%, to $3.3 million compared to the prior year quarter. This increase was primarily due to the $1.3 million of expenses related to the natural gas properties recently acquired in combination with an increase of $0.4 million related to our previously existing natural gas properties.

Impairment of gas properties. During the current quarter, the gross carrying value of the Company’s gas properties exceeded the full cost ceiling limitation and, as such, a $42.3 million impairment of gas properties was recorded.

General and administrative. General and administrative expenses decreased by $0.1 million, or 9%, to $1.4 million compared to the prior year quarter. This decrease was primarily due to decreased compensation.

Restructuring costs. During the current year quarter, we recognized pretax restructuring costs of $0.8 million. The restructuring costs included cash payments to our former Chief Executive Officer (“CEO”) of $0.6 million, share-based awards conveyed to our former CEO of $0.1 million and legal and consulting services of $0.1 million. No such expenses were incurred in the prior year quarter.

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Realized gains on derivative contracts. Realized gains on derivative contracts increased by $3.8 million, or 246%, to $5.3 million compared to the prior year quarter. Realized losses represent net cash flow settlements paid to the contract counterparty, while realized gains represent net cash flow settlements paid to us from the contract 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 losses (gains) from the change in market value of open derivative contracts. Unrealized losses on open derivative contracts were $10.2 million in the current quarter as compared to unrealized gains of $0.2 million in the prior year quarter. The current quarter unrealized loss position was made up of $1.6 million in unrealized net losses on derivative contracts acquired as part of our coalbed methane gas property acquisition, in addition to unrealized net losses of $8.6 million on pre-acquisition or recently executed derivative contracts. Unrealized gains and losses 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.

Interest expense (net of amounts capitalized). Interest expense increased by $0.4 million, or 54%, to $1.3 million compared to the prior year quarter. The increase was primarily due to a higher average outstanding balance under our Credit Agreement in the current year quarter, partially offset by a lower average interest rate under our Credit Agreement in the current year quarter.

Income tax expense. The income tax expense for the three months ended June 30, 2012 was different than the amount computed using the statutory rate primarily due to a $20.4 million valuation allowance on our deferred tax asset. A reconciliation of the effective tax rate to the statutory rate is as follows:

	U.S.					Canada					Total
Amount computed using statutory rates	$	(18,327,815	)	34.00	%	$	1,836		25.00	%	$	(18,325,979	)	34.00	%
State income taxes—net of federal benefit	(1,929,656		)	3.58	%	—			0.00	%	(1,929,656		)	3.58	%
Valuation Allowance	20,378,274			-37.80	%	(1,836		)	-25.00	%	20,376,438			-37.80	%
Nondeductible items and other	(114,553		)	0.21	%	—			0.00	%	(114,553		)	0.21	%
Income tax provision	$	6,250		-0.01	%	$	—		0.00	%	$	6,250		-0.01	%

Discontinued operations, net of tax. During the current year quarter, we incurred a loss of $0.7 million related to the sale of our Canadian subsidiary, Hudson’s Hope Gas, Ltd. No such sale took place in the prior year quarter.

Six months ended June 30, 2012 compared with six months ended June 30, 2011

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

	Six Months Ended June 30,
	2012			2011			Change
	(In thousands)
Gas sales	$	17,855		$	16,182		10	%
Lease operating expenses	$	8,933		$	5,811		54	%
Compression expense	$	2,453		$	1,247		97	%
Transportation expense	$	2,087		$	630		231	%
Production taxes	$	834		$	688		21	%
Depreciation, depletion and amortization	$	6,921		$	3,224		115	%
Impairment of gas properties	$	58,035		$	—		NM
General and administrative	$	2,668		$	2,925		-9	%
Restructuring costs	$	765		$	—		NM
Realized gains on derivative contracts	$	(10,104	)	$	(5,033	)	101	%
Unrealized losses from the change in market value of open derivative contracts	$	4,979		$	2,653		88	%
Interest expense, net of amounts capitalized	$	2,544		$	1,664		53	%
Income tax expense	$	44,031		$	907		NM
Discontinued operations	$	696		$	94		NM

NM-Not Meaningful

Gas sales. Gas sales increased by $1.7 million, or 10%, to $17.9 million compared to the prior year period. The increase in gas sales was primarily the result of higher production volumes, of which 3.2 Bcf was due to our November 18, 2011 acquisition of coalbed methane gas properties, while 0.2 Bcf was due to increased production in our previously existing properties, partially offset by a 43% decrease in natural gas prices, excluding hedging transactions.

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Lease operating expenses. Lease operating expenses increased by $3.1 million, or 54%, to $8.9 million compared to the prior year period. The $3.1 million increase in lease operating expenses consisted of $3.4 million increase due to our recent acquisition of coalbed methane gas properties partially offset by a $0.3 million decrease in our previously existing properties.

Compression expense. Compression expense increased by $1.2 million, or 97%, to $2.5 million compared to the prior year period. The increase was primarily attributable to the $1.0 million of expenses related to our recently purchased gas properties combined with an increase of $0.2 million related to our previously existing properties. The increase in compression expenses in our previously existing properties was due to increased production.

Transportation expense. Transportation expense increased by $1.5 million, or 231%, to $2.1 million compared to the prior year period. The increase was primarily due to the recent acquisition of coalbed methane gas properties. Transportation expenses remained relatively flat in our previously existing gas properties.

Production taxes. Production taxes increased by $0.1 million, or 21%, to $0.8 million compared to the prior year period. The increase was primarily attributable to the $0.3 million of expenses related to our recently purchased gas properties partially offset by a decrease of $0.2 million related to our previously existing properties.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $3.7 million, or 115%, to $6.9 million compared to the prior year period. This increase was primarily due to the $3.1 million of expenses related to the natural gas properties recently acquired in combination with an increase of $0.6 million related to our previously existing natural gas properties.

Impairment of gas properties. During the current year period, the gross carrying value of the Company’s gas properties exceeded the full cost ceiling limitation and, as such, a $58.0 million impairment of gas properties was recorded.

General and administrative. General and administrative expenses decreased by $0.3 million, or 9%, to $2.7 million compared to the prior year period. This decrease was primarily due to decreased compensation.

Restructuring costs. During the current year period, we recognized pretax restructuring costs of $0.8 million. The restructuring costs included cash payments to our former CEO of $0.6 million, share-based awards conveyed to our former CEO of $0.1 million and legal and consulting services of $0.1 million. No such expenses were incurred in the prior year period.

Realized gains on derivative contracts. Realized gains on derivative contracts increased by $5.1 million, or 101%, to $10.1 million compared to the prior year period. Realized losses represent net cash flow settlements paid to the contract counterparty, while realized gains represent net cash flow settlements paid to us from the contract 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 losses from the change in market value of open derivative contracts. Unrealized losses on open derivative contracts increased by $2.3 million, or 88%, to $5.0 million compared to the prior year period. The current period unrealized loss position was almost entirely related to pre-acquisition or newly executed derivative contracts. Unrealized gains and losses 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.

Interest expense (net of amounts capitalized). Interest expense increased by $0.9 million, or 53%, to $2.5 million compared to the prior year period. The increase was primarily due to a higher average outstanding balance under our Credit Agreement in the current year period, partially offset by a lower average interest rate under our Credit Agreement in the current year period.

Income tax expense. The income tax expense for the six months ended June 30, 2012 was different than the amount computed using the statutory rate primarily due to a $67.7 million valuation allowance on our deferred tax asset. A reconciliation of the effective tax rate to the statutory rate is as follows:

	U.S.					Canada					Total
Amount computed using statutory rates	$	(21,354,829	)	34.00	%	$	(3,307	)	25.00	%	$	(21,358,136	)	34.00	%
State income taxes—net of federal benefit	(2,240,209		)	3.57	%	—			0.00	%	(2,240,209		)	3.57	%
Valuation Allowance	67,728,192			-107.83	%	3,307			-25.00	%	67,731,499			-107.82	%
Nondeductible items and other	(102,454		)	0.16	%	—			0.00	%	(102,454		)	0.16	%
Income tax provision	$	44,030,700		-70.10	%	$	—		0.00	%	$	44,030,700		-70.09	%

Discontinued operations, net of tax. During the current year period, we incurred a loss of $0.7 million related to the sale of our Canadian subsidiary, Hudson’s Hope Gas, Ltd. No such sale took place in the prior year period.

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Liquidity and Capital Resources

Cash Flows and Liquidity

Calculation Date	Fee Amount	Date Payable
11/25/2012	75 bps	12/1/2012
2/25/2013	100 bps	3/1/2013
5/25/2013	125 bps	6/1/2013
8/25/2013	150 bps	9/1/2013
11/25/2013	175 bps	12/1/2013

Quarter Ending	Maximum Principal Outstanding
9/30/2012	$	146,200,000
12/31/2012	$	139,300,000
3/31/2013	$	136,000,000
6/30/2013	$	132,700,000
9/30/2013	$	131,500,000
12/31/2013	$	129,000,000

Price Risk Management Activities

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 are limited by our Credit Agreement to the amount of our natural gas derivative contracts during any period to no more than 85% 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

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floor) future price. 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 unaudited Consolidated Balance Sheets and Consolidated Statements of Operations.

Commodity Price Risk and Related Hedging Activities

At June 30, 2012, we had the following natural gas collar positions:

Period	Volume (MMBtu)	Sold Ceiling		Bought Floor		Sold Floor	Fair Value
January 2014 through December 2015	3,650,000	$	4.30	$	3.60	—	$	(439,438	)
January 2014 through December 2015	3,650,000	$	4.20	$	3.50	—	(729,409		)
	7,300,000						$	(1,168,847	)

At June 30, 2012, we had the following natural gas swap positions:

Period	Volume (MMBtu)	Fixed Price		Fair Value
July through December 2012	276,000	$	5.11	$	592,738
July through December 2012	114,000	$	5.12	245,966
July through December 2012	526,051	$	6.85	2,044,859
July through December 2012	247,337	$	6.99	1,005,101
July through December 2012	404,093	$	7.05	1,678,083
July through October 2012	492,000	$	5.73	1,426,944
July through October 2012	984,000	$	4.94	2,072,357
July through October 2012	1,845,000	$	2.89	115,547
November 2012 through March 2013	604,000	$	6.42	1,821,273
November 2012 through March 2013	906,000	$	5.50	1,906,376
November 2012 through March 2013	4,128,000	$	3.81	796,037
November 2012 through March 2013	4,128,000	$	3.82	836,969
January 2013 through December 2013	2,190,000	$	3.60	42,024
April 2013 through December 2013	2,750,000	$	3.25	(889,214		)
	19,594,481			$	13,695,060

At June 30, 2012, we had the following natural gas basis swap position:

Period	Volume (MMBtu)	Fixed Basis		Fair Value
July through December 2012	276,000	$	0.04	$	20,018

Forward Physical Sale Contract

Our production is sold at an “all-in” price which includes the market price for natural gas plus a “basis differential”. In January 2011, we agreed to sell gross volumes of 16,000 MMBtu/day of natural gas from our Pond Creek field for the period February 2011 through March 2012 through a forward physical sale contract with our existing purchaser at a price equal to the last day settlement price for the New York Mercantile Exchange (“NYMEX”) contract for the month of sale plus a basis differential of $0.15, $0.115, and $0.13 for the periods February 2011 through March 2011, April 2011 through October 2011, and November 2011 through March 2012, respectively. There were no remaining volumes at June 30, 2012. As of December 31, 2011, we had fixed the NYMEX settle on a portion of the aforementioned forward sale as follows:

Period	Volume (MMBtu)	Fixed Market Price		Fixed Basis Differential		All-In Price		Gross Sale
January through March 2012	273,000	$	5.20	$	0.130	$	5.330	$	1,419,600

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The remaining volumes giving effect for the fixed amounts denoted above are as follows:

Period	Volume (MMBtu)	Fixed Basis Differential
January through March 2012	1,183,000	$	0.130

The aforementioned forward physical sale contract meets the definition of a derivative contract under ASC 815. However, it qualifies for normal purchase and sale exemption and, as such, we have elected not to record it on the Consolidated Balance Sheets (Unaudited) using mark-to-market accounting.

Capital Expenditures and Capital Resources

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
Capital expenditures:
Leasehold acquisition	$	361,540		$	185,154	$	510,159		$	535,718
Exploration	—			—		—			3,000
Development (1)	(274,773		)	5,003,966		(337,979		)	7,503,731
Asset retirement obligations	241,317			10,941		247,440			19,714
Other items (primarily capitalized overhead)	83,294			256,281		208,196			520,666

Total capital expenditures	$	411,378		$	5,456,342	$	627,816		$	8,582,829

(1) Includes insurance refunds related to our gas properties.

Based on the prevailing low prices for natural gas, our Board of Directors has established a limited capital budget for 2012. We expect to spend $1.5 million in capital in 2012 primarily for maintenance operations associated with our existing properties.

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 2011 Annual Report on Form 10-K that we filed with the SEC on March 30, 2012.

Recent Pronouncements

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-06, Improving Disclosures about Fair Value Measurements. This update provides amendments to Subtopic 820-10 and requires new disclosures for 1) significant transfers in and out of Level 1 and Level 2 and the reasons for such transfers and 2) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements. In addition, this update amends Subtopic 820-10 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements). The provisions in ASU 2010-06 are now applicable to interim and annual reporting periods. The adoption of ASU 2010-06 did not impact the Company’s operating results, financial position or cash flows, but did impact the Company’s disclosures on fair value measurements. See Note 8—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements (Unaudited).

On June 16, 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income, which revises the manner in which entities present comprehensive income in their financial statements. The new guidance removes the presentation options in Accounting Standards Codification (“ASC”) 220 and requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. The ASU does not change the items that must be reported in other comprehensive income. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Early adoption is permitted. The Company has not elected to early adopt and is still evaluating the effect on its disclosures. The amendments do not require incremental disclosures in addition to those required by ASC 250 or any transition guidance.

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these amendments were made to eliminate unnecessary wording differences between U.S. GAAP and IFRS. However, some could change how the fair value measurement guidance in ASC 820 is applied. The ASU is effective for interim and annual periods beginning after December 15, 2011. The Company is still evaluating the effect on its disclosures.

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 and six months ended June 30, 2012, a 10% decrease in the prices received for natural gas production would have decreased our gas revenues by approximately $0.8 million and $1.8 million, respectively, which would have been offset approximately $0.7 million and $1.3 million, respectively, by realized gas hedging gains.

Interest Rate Risk. We have long-term debt subject to the risk of loss associated with movements in interest rates. At June 30, 2012, we had $148.6 million outstanding under our Credit Agreement. For the three months ended June 30, 2012 and 2011, interest on the borrowings averaged 2.99% and 3.39% per annum, respectively. For the six months ended June 30, 2012 and 2011, interest on the borrowings averaged 2.94% and 3.40% per annum, respectively. All of the debt outstanding under our Credit Agreement accrues interest at floating or market rates. Fluctuations in market interest rates will cause our interest costs to fluctuate. Based upon the weighted average balance outstanding under our Credit Agreement, a 1% increase in market interest rates would have increased interest expense and negatively impacted our cash flows for the three and six months ended June 30, 2012 by approximately $0.4 million and $0.4 million, respectively.

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 June 30, 2012 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. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act 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.

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Part II. OTHER INFORMATION

Item 1. Legal Proceedings

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 June 30, 2012, 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 has been no changes from the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2011.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosure

Not applicable.

Item 5. Other Information

None.

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.

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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: August 13, 2012	By	/S/ TONY OVIEDO
		Tony Oviedo, Senior Vice President, Chief Financial Officer, Chief Accounting Officer and Controller
		(Principal Financial Officer)

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INDEX TO EXHIBITS

Exhibit Number		Exhibits

10.1		Separation Agreement, dated April 30, 2012, between GeoMet, Inc. and J. Darby Seré (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K filed on May 3, 2012).

10.2		Consulting Agreement, dated April 30, 2012, between GeoMet, Inc. and J. Darby Seré (incorporated herein by reference to Exhibit 10.2 to the Company’s Form 8-K filed on May 3, 2012).

10.3		Amended and Restated Employment Agreement, dated May 14, 2012, between GeoMet, Inc. and William C. Rankin (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K filed on May 18, 2012).

10.4		Employment Agreement, dated May 14, 2012, between GeoMet, Inc. and Tony Ovideo (incorporated herein by reference to Exhibit 10.2 to the Company’s Form 8-K filed on May 18, 2012).

10.5		Employment Agreement, dated May 14, 2012, between GeoMet, Inc. and Brett S. Camp (incorporated herein by reference to Exhibit 10.3 to the Company’s Form 8-K filed on May 18, 2012).

10.6		Second Amendment to Fifth Amended and Restated Credit Agreement, dated as of June 21, 2012, by and among GeoMet, Inc., Bank of America, N.A, as Administrative Agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K filed on June 25, 2012).

10.7		Third Amendment to Fifth Amended and Restated Credit Agreement, dated as of July 25, 2012, by and among GeoMet, Inc., Bank of America, N.A, as Administrative Agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K filed on July 31, 2012).

10.8

Fourth Amendment to Fifth Amended and Restated Credit Agreement dated as of August 8, 2012, by and among the Company, Bank of America, N.A. as administrative agent, and the lenders named therein (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K filed on August 10, 2012).

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).

101**		Interactive Data Files.

*	Attached hereto
**	Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability.