Edgar Filing: GeoMet, Inc.

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2011

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

For the transition period from to

Commission File Number 001-32960

GeoMet, Inc.

(Exact name of registrant as specified in its charter)

Delaware

76-0662382

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification Number)

909 Fannin, Suite 1850

Houston, Texas 77010

(713) 659-3855

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

N/A

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

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

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

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

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

As of November 1, 2011, 40,010,188 shares and 4,549,537 shares, respectively, of the registrant’s common stock and preferred stock, par value $0.001 per share, were outstanding.

TABLE OF CONTENTS


Part I. Financial Information

Item 1.	Financial Statements

	Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010 (Unaudited)	3

	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2011 and 2010 (Unaudited)	4

	Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2011 and 2010 (Unaudited)	5

	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010 (Unaudited)	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	30

Item 4.	Controls and Procedures	30

Part II. Other Information

Item 1.	Legal Proceedings	32

Item 1A.	Risk Factors	32

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32

Item 3.	Defaults Upon Senior Securities	32

Item 4.	[Removed and Reserved]	32

Item 5.	Other Information	32

Item 6.	Exhibits	32

Part I. FINANCIAL INFORMATION

Item 1. Financial Statements

GEOMET, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

(Unaudited)


	September 30, 2011			December 31, 2010
ASSETS
Current Assets:
Cash and cash equivalents	$	462,722		$	536,533
Accounts receivable, both amounts net of allowance of $60,848		2,472,195			2,600,319
Inventory		621,011			1,002,207
Derivative asset—natural gas contracts		7,121,202			7,087,775
Other current assets		1,115,772			951,622

Total current assets		11,792,902			12,178,456

Gas properties—utilizing the full cost method of accounting:
Proved gas properties		488,795,217			475,917,727
Other property and equipment		3,426,443			3,405,502

Total property and equipment		492,221,660			479,323,229
Less accumulated depreciation, depletion, amortization and impairment of gas properties		(377,710,024	)		(373,235,875	)

Property and equipment—net		114,511,636			106,087,354

Other noncurrent assets:
Derivative asset—natural gas contracts		2,044,078			2,186,767
Deferred income taxes		45,854,932			48,202,861
Other		769,823			1,430,584

Total other noncurrent assets		48,668,833			51,820,212

TOTAL ASSETS	$	174,973,371		$	170,086,022

LIABILITIES, MEZZANINE AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	5,888,096		$	5,950,861
Accrued liabilities		1,747,122			2,306,020
Deferred income taxes		2,373,602			2,206,531
Derivative liability—interest rate swaps		—			4,592
Asset retirement liability		32,121			32,893
Current portion of long-term debt		89,693			132,743

Total current liabilities		10,130,634			10,633,640

Long-term debt		81,295,386			80,863,419
Asset retirement liability		5,931,702			5,465,798
Other long-term accrued liabilities		16,291			40,728

TOTAL LIABILITIES		97,374,013			97,003,585

Commitments and contingencies (Note 13)
Mezzanine equity:
Series A Convertible Redeemable Preferred Stock—net of offering costs of $1,660,436; redemption amount $45,495,370; $.001 par value; 7,401,832 shares authorized, 4,549,537 and 4,148,538 shares were issued and outstanding at September 30, 2011 and December 31, 2010, respectively.		27,262,718			22,074,320
Stockholders’ 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 39,973,810 and 39,758,484 at September 30, 2011 and December 31, 2010, respectively		39,974			39,744
Treasury stock—10,432 shares at September 30, 2011 and December 31, 2010		(94,424	)		(94,424	)
Paid-in capital		202,910,411			207,548,596
Accumulated other comprehensive loss		(1,309,211	)		(1,324,154	)
Retained deficit		(150,966,044	)		(154,918,736	)
Less notes receivable		(244,066	)		(242,909	)

Total stockholders’ equity		50,336,640			51,008,117

TOTAL LIABILITIES, MEZZANINE AND STOCKHOLDERS’ EQUITY	$	174,973,371		$	170,086,022

See accompanying Notes to Consolidated Financial Statements (Unaudited)

GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Operations

(Unaudited)


	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010
Revenues:
Gas sales	$	8,519,980		$	8,239,345		$	24,701,708		$	25,784,384
Operating fees and other		64,984			77,121			210,670			222,116

Total revenues		8,584,964			8,316,466			24,912,378			26,006,500
Expenses:
Lease operating expense		3,018,576			2,877,385			8,871,026			8,797,639
Compression and transportation expense		1,084,432			1,095,803			2,965,488			3,175,642
Production taxes		390,045			226,785			1,077,754			723,053
Depreciation, depletion and amortization		1,887,794			1,561,142			5,142,308			4,656,745
General and administrative		1,157,515			1,206,476			4,099,854			3,999,041
Acquisition costs		370,621			—			370,621			—
Terminated transaction costs		—			—			—			1,402,534
Realized gains on natural gas derivative contracts		(1,681,756	)		(1,824,915	)		(6,714,874	)		(5,495,893	)
Unrealized (gains) losses on natural gas derivative contracts		(2,543,752	)		(5,096,346	)		109,262			(9,764,362	)

Total operating expenses		3,683,475			46,330			15,921,439			7,494,399
Operating income		4,901,489			8,270,136			8,990,939			18,512,101
Other income (expense):
Interest income		4,207			8,754			12,968			39,615
Interest expense		(868,583	)		(1,510,299	)		(2,532,355	)		(4,177,935	)
Unrealized gain from change in fair value of derivative liability—Series A Convertible Redeemable Preferred Stock		—			1,595,670			—			1,595,670
Other		12,501			(24,474	)		8,176			(41,176	)

Total other income (expense)		(851,875	)		69,651			(2,511,211	)		(2,583,826	)

Income before income taxes		4,049,614			8,339,787			6,479,728			15,928,275
Income tax expense		(1,619,739	)		(3,812,588	)		(2,527,036	)		(7,136,047	)

Net income	$	2,429,875		$	4,527,199		$	3,952,692		$	8,792,228

Accretion of Series A Convertible Redeemable Preferred Stock		(449,347	)		(73,532	)		(1,308,519	)		(73,532	)
Paid-in-kind dividends on Series A Convertible Redeemable Preferred Stock		(1,377,880	)		(236,111	)		(4,009,990	)		(236,111	)
Cash dividends paid on Series A Convertible Redeemable Preferred Stock		(792	)		—			(2,014	)		—

Net income (loss) available to common stockholders	$	601,856		$	4,217,556		$	(1,367,831	)	$	8,482,585

Net income (loss) per common share:
Basic	$	0.02		$	0.11		$	(0.03	)	$	0.22

Diluted	$	0.02		$	0.10		$	(0.03	)	$	0.21

Weighted average number of common shares:
Basic		39,640,275			39,321,326			39,576,684			39,241,671

Diluted		39,968,064			45,006,945			39,576,684			41,207,732

See accompanying Notes to Consolidated Financial Statements (Unaudited).

GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income

(Unaudited)


	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
Net income	$	2,429,875	$	4,527,199	$	3,952,692	$	8,792,228
Gain on foreign currency translation adjustment, net of tax		3,342		199		4,082		6,133
Gain on interest rate swap, net of tax		—		70,841		10,862		353,685

Other comprehensive income	$	2,433,217	$	4,598,239	$	3,967,636	$	9,152,046

See accompanying Notes to Consolidated Financial Statements (Unaudited).

GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)


	Nine Months Ended September 30,
	2011			2010
Cash flows provided by operating activities:
Net income	$	3,952,692		$	8,792,228
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, depletion and amortization		5,142,308			4,656,745
Amortization of debt issuance costs		435,702			400,786
Terminated transaction costs		—			666,306
Deferred income tax expense		2,508,286			7,117,297
Unrealized losses (gains) on natural gas derivative contracts		122,246			(9,764,362	)
Unrealized gain from change in fair value of derivative liability—Series A Convertible Redeemable Preferred Stock		—			(1,595,670	)
Stock-based compensation		576,345			302,362
Loss on sale of assets		1,164			53,040
Accretion expense		407,708			362,633
Changes in operating assets and liabilities:

Accounts receivable		127,815			760,938
Inventory		(571,490	)		338,021
Other current assets		(143,833	)		(57,599	)
Accounts payable		(401,321	)		297,905
Other accrued liabilities		(574,953	)		(680,216	)

Net cash provided by operating activities		11,582,669			11,650,414

Cash flows used in investing activities:
Capital expenditures		(12,118,713	)		(7,425,981	)
Proceeds from sale of other property and equipment		—			58,937
Other assets		246,134			84,197

Net cash used in investing activities		(11,872,579	)		(7,282,847	)

Cash flows provided by (used in) financing activities:
Proceeds from sale of preferred stock		—			40,000,000
Proceeds from exercise of stock options		3,791			54,137
Proceeds from revolver borrowings		24,300,000			18,250,000
Payments on revolver		(23,800,000	)		(58,250,000	)
Deferred financing costs		(172,507	)		(3,941,557	)
Deferred financing costs related to terminated transactions		—			(666,306	)
Payments on other debt		(111,083	)		(102,001	)
Purchase and cancellation of treasury stock		(2,145	)		—
Cash dividends paid on Series A Convertible Redeemable Preferred Stock		(2,014	)		—

Net cash provided by (used in) financing activities		216,042			(4,655,727	)
Effect of exchange rate changes on cash		57			12,254

Decrease in cash and cash equivalents		(73,811	)		(275,906	)
Cash and cash equivalents at beginning of period		536,533			973,720

Cash and cash equivalents at end of period	$	462,722		$	697,814

Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest expense		2,573,915			4,374,429

Income taxes		18,750			—

Significant noncash investing and financing activities:
Accrued capital expenditures		1,484,715			1,236,665

See accompanying Notes to Consolidated Financial Statements (Unaudited).

GEOMET, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(Unaudited)

Note 1—Organization and Our Business

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

The accompanying unaudited consolidated financial statements include our accounts and those of our wholly-owned subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. The unaudited consolidated financial statements reflect, in the opinion of our management, all adjustments, consisting only of normal and recurring adjustments, necessary to present fairly the financial position as of, and results of operations for, the interim periods presented. These unaudited consolidated financial statements have been prepared in accordance with the guidelines of interim reporting; therefore, they do not include all disclosures required for our year-end audited consolidated financial statements prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Interim period results are not necessarily indicative of results of operations or cash flows for the full year. These unaudited consolidated financial statements included herein should be read in conjunction with the audited consolidated financial statements for the fiscal year ended December 31, 2010 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 April 6, 2011.

Note 2—Recent Pronouncements

In December 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-29, Disclosure of Supplementary Pro Forma Information for Business Combinations (ASU 2010-29). ASU 2010-29 requires a public entity who discloses comparative pro forma information for business combinations that occurred in the current reporting period to disclose revenue and earnings of the combined entity as though the business combination(s) occurred as of the beginning of the comparable prior annual period only. This update also expands the supplemental pro forma disclosures required to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. ASU 2010-29 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010 and early adoption is permitted. The Company will apply the provisions of this update for any business combinations that occur after January 1, 2011.

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.

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 is still evaluating the effect on its disclosures.

Note 3—Net Income (Loss) Per Common Share

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Net income	$	2,429,875		$	4,527,199		$	3,952,692		$	8,792,228
Accretion of Series A Convertible Redeemable Preferred Stock		(449,347	)		(73,532	)		(1,308,519	)		(73,532	)
PIK dividends on Series A Convertible Redeemable Preferred Stock		(1,377,880	)		(236,111	)		(4,009,990	)		(236,111	)
Cash dividends paid on Series A Convertible Redeemable Preferred Stock		(792	)		—			(2,014	)		—

Net income (loss) available to common stockholders	$	601,856		$	4,217,556		$	(1,367,831	)	$	8,482,585

Net income (loss) per common share—basic	$	0.02		$	0.11		$	(0.03	)	$	0.22

Weighted average number of common shares—basic		39,640,275			39,321,326			39,576,684			39,241,671

A reconciliation of net income (loss) per common share—diluted is as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011			2010
Net income (loss) available to common stockholders	$	601,856	$	4,217,556	$	(1,367,831	)	$	8,482,585
Addback: Accretion of Series A Convertible Redeemable Preferred Stock		—		73,532		—			73,532
Addback: PIK dividends on Series A Convertible Redeemable Preferred Stock		—		236,111		—			236,111
Addback: Cash dividends paid on Series A Convertible Redeemable Preferred Stock		—		—		—			—

Net income (loss) available to common stockholders—diluted	$	601,856	$	4,527,199	$	(1,367,831	)	$	8,792,228

Net income (loss) per common share—diluted	$	0.02	$	0.10	$	(0.03	)	$	0.21

Weighted average number of common shares:
Basic		39,640,275		39,321,326		39,576,684			39,241,671

Add potentially dilutive securities:
Series A Convertible Redeemable Preferred Stock		—		5,685,619		—			1,916,033
Stock options, non-vested restricted stock and non-vested restricted stock units		327,789		—		—			50,028

Diluted		39,968,064		45,006,945		39,576,684			41,207,732

Net income per common share—diluted for the three months ended September 30, 2011 excluded the effect of 4,411,749 shares of Series A Convertible Redeemable Preferred Stock (33,936,532 in dilutive shares, as converted, which assumes conversion on the first day of the period) because their effect would have been anti-dilutive. In accordance with ASC 260, in computing the dilutive effect of convertible securities, Net income available to common stockholders is also adjusted to add back any convertible preferred dividends and accretion unless the preferred shares are anti-dilutive. As such, there was no add back to Net income available to

common stockholders for the three months ended September 30, 2011 for accretion of, and dividends paid for, Series A Convertible Redeemable Preferred Stock (cash and PIK) of $449,347 and $1,378,672, respectively, in computing Net income per common share—diluted as the preferred shares were anti-dilutive.

Net loss per common share—diluted for the nine months ended September 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, 355,705 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. For the preferred shares, there was no add back to Net loss available to common stockholders for the nine months ended September 30, 2011 for accretion of, and dividends paid for, Series A Convertible Redeemable Preferred Stock (cash and PIK) of $1,308,519 and $4,012,004, respectively, in computing Net loss per common share—diluted as the preferred shares were anti-dilutive.

Note 4—Gas Properties

The method of accounting for gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. We use the full cost method of accounting for gas properties as prescribed by the SEC. Under this method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of our gas properties are capitalized and segregated into United States of America (“U.S.”) and Canadian cost centers. The Canadian cost center was fully impaired in 2009 and remains fully impaired at September 30, 2011.

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.

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. The ceiling test is performed separately for our U.S. and Canadian cost centers. If capitalized costs (net of accumulated depreciation, depletion and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date.

The ceiling test is calculated using the unweighted arithmetic average of the natural gas price on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions, as allowed by the guidelines of the SEC. In addition, subsequent to the adoption of ASC 410-20-25, Accounting for Asset Retirement Obligations, the future cash outflows associated with settling asset retirement obligations were not included in the computation of the discounted present value of future net revenues for the purposes of the ceiling test calculation.

No impairments were recorded during the three and nine months ended September 30, 2011 and 2010. Future adverse changes could lead to an impairment of all or a portion of our full cost pool in future periods which could significantly reduce earnings during the period in which the impairment occurs, and would result in a corresponding reduction to the full cost pool and stockholders’ equity.

Note 5—Asset Retirement Liability

We record an asset retirement obligation (“ARO”) on the consolidated balance sheets and capitalize the asset retirement costs in gas properties in the period in which the retirement obligation is incurred. The amount of the ARO and the costs capitalized are equal to the estimated future costs to satisfy the obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date we incurred the abandonment obligation using an assumed interest rate. Once the ARO is recorded, it is then accreted to its estimated future value using the same assumed interest rate.

The following table details the changes to our asset retirement liability for the nine months ended September 30, 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		65,684
Accretion		407,708
Foreign currency translation		(8,260	)

Asset retirement liability at September 30, 2011		5,963,823
Less: Current portion of liability		(32,121	)

Long-term asset retirement liability	$	5,931,702

The following table details the changes to our asset retirement liability for the nine months ended September 30, 2010:


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

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

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

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

Note 6—Derivative Instruments and Hedging Activities

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 generally limit the amount of our natural gas derivative contracts during any period to no more than 50% to 70% of the then expected gas production for such future periods. Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Costless collars set both a maximum ceiling (a sold ceiling) and a minimum floor (a bought floor) future price. 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 and consolidated statements of operations.

Commodity Price Risk and Related Hedging Activities

At September 30, 2011, we had no natural gas collar positions.

At December 31, 2010, we had the following natural gas collar position:


Period	Volume (MMBtu)		Sold Ceiling		Bought Floor		Sold Floor		Fair Value
January through March 2011		360,000	$	7.45	$	6.50		—		775,853

At September 30, 2011, we had the following natural gas swap positions:


Period	Volume (MMBtu)		Fixed Price		Fair Value
October 2011		124,000	$	6.37		323,761
October 2011		124,000	$	5.37		199,142
October 2011		124,000	$	5.43		207,202
November 2011 through March 2012		608,000	$	7.12		1,894,183
November 2011 through March 2012		608,000	$	6.12		1,283,872
November 2011 through March 2012		912,000	$	5.08		983,019
April through October 2012		856,000	$	5.73		1,308,794
April through October 2012		1,712,000	$	4.94		1,262,519
November 2012 through March 2013		604,000	$	6.42		1,010,165
November 2012 through March 2013		906,000	$	5.50		692,623

		6,578,000			$	9,165,280

At December 31, 2010, we had the following natural gas swap positions:


Period	Volume (MMBtu)		Fixed Price		Fair Value
January through March 2011		360,000	$	6.67		836,287
January through March 2011		540,000	$	7.27		1,576,095
April through October 2011		856,000	$	6.37		1,572,738
April through October 2011		856,000	$	5.37		715,726
April through October 2011		856,000	$	5.43		771,155
November 2011 through March 2012		608,000	$	7.12		1,216,885
November 2011 through March 2012		608,000	$	6.12		611,002
November 2011 through March 2012		912,000	$	5.08		(19,449	)
April through October 2012		856,000	$	5.73		653,211
April through October 2012		1,712,000	$	4.94		(34,286	)
November 2012 through March 2013		604,000	$	6.42		563,413
November 2012 through March 2013		906,000	$	5.50		35,912

		9,674,000			$	8,498,689

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. As of September 30, 2011, we 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
October 2011		124,000	$	4.80	$	0.115	$	4.915	$	609,460
November 2011 through March 2012		456,000	$	5.20	$	0.130	$	5.330		2,430,480

		580,000							$	3,039,940

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


Period	Volume (MMBtu)		Fixed Basis Differential
October 2011		372,000	$	0.115
November 2011 through March 2012		1,976,000	$	0.130

		2,348,000

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.

Interest Rate Risks and Related Hedging Activities

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

At September 30, 2011, we had no interest rate swaps. At December 31, 2010, we had the following interest rate swap:


Description	Effective date		Designated maturity date		Fixed rate(1)			Notional amount		Fair Value
Floating-to-fixed swap		1/6/2009		1/6/2011		1.38	%	$	5,000,000	$	(4,592	)

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

On September 14, 2010, we de-designated the remaining two interest rate swaps which we had previously designated as cash flow hedges under ASC 815-20-25. The de-designation resulted from entering into the Fourth Amended and Restated Credit Agreement (“Existing Credit Agreement”) which replaced our Third Amended and Restated Credit Agreement. In the new agreement, the notional and interest rates no longer match, and therefore, these two interest rate swaps were no longer effective hedges under ASC 815-20-25. Subsequently, we accounted for the remaining interest rate swaps on a mark-to-market basis which gave rise to both realized and unrealized gains and losses recorded in Interest expense in the Consolidated Statements of Operations. Amounts in accumulated other comprehensive income were frozen and reclassified into earnings as the forecasted transactions impacted earnings. For the three and nine months ended September 30, 2011 and 2010, we recognized no ineffective portion of our cash flow hedges.

We have reviewed the financial strength of our hedge counterparties and believe our credit risk to be minimal. Our hedge counterparties are participants in our Existing Credit Agreement and the collateral for the outstanding borrowings under our Existing 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 Existing 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 and interest rate swaps using the income approach. The income approach uses valuation techniques that convert future cash flows to a single discounted value. ASC 820-10-55 clarifies that a fair value measurement for an asset or liability reflects its nonperformance risk, the risk that the obligation will not be fulfilled. Because nonperformance risk includes our counterparties’ and our credit risk, we have considered the effect of 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 our long-term debt. The following is a description of the valuation methodologies used for our derivative instruments measured at fair value:

•

Natural Gas Derivative Contracts—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.

•

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

We did not have any transfers of assets and liabilities between Level 1 and Level 2 of the fair value measurement hierarchy during the three and nine months ended September 30, 2011. 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 were as follows:

	0000000000		0000000000	0000000000		0000000000	0000000000		0000000000	0000000000		0000000000
	Asset Derivatives						Liability Derivatives
	September 30, 2011			December 31, 2010			September 30, 2011			December 31, 2010
	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)	$	4,592
Natural gas derivative contracts	Derivative asset (current)		7,121,202	Derivative asset (current)		7,087,775	Derivative liability (current)		—	Derivative liability (current)		—
Natural gas derivative contracts	Derivative asset (non- current)		2,044,078	Derivative asset (non- current)		2,186,767	Derivative liability (non- current)		—	Derivative liability (non- current)		—

Total derivatives not designated as hedging instruments under ASC 815-20-25		$	9,165,280		$	9,274,542		$	—		$	4,592

The following (gains) losses on our hedging instruments included in the consolidated statements of operations and other comprehensive income (“OCI”) are as follows:

The Effect of Derivative Instruments on the Consolidated Statements of Operations and

Other Comprehensive Income for the Three and Nine Months Ended September 30, 2011 and 2010


	Location of (Gain) or Loss Recognized in Income on Derivative	Amount of (Gain) or Loss Recognized in Income on Derivative
		Three months ended September 30,						Nine months ended September 30,
Derivatives		2011			2010			2011			2010
Derivatives designated as hedging instruments under ASC 815-20-25
Interest rate swaps	Interest expense	$	—		$	142,814		$	—		$	546,157

Total loss		$	—		$	142,814		$	—		$	546,157

Derivatives not designated as hedging instruments under ASC 815-20-25
Derivative liability—Series A Convertible Redeemable Preferred Stock	Unrealized gain from change in fair value of derivative liability—Series A	$	—		$	(1,595,670	)	$	—		$	(1,595,670	)
Natural gas collar positions	Realized gains on natural gas derivative contracts	$	(1,681,756	)	$	(1,824,915	)	$	(6,714,874	)	$	(5,495,893	)
Natural gas collar positions	Unrealized (gains) losses on natural gas derivative contracts		(2,543,752	)		(5,096,346	)		109,262			(9,764,362	)

Total (gain) loss		$	(4,225,508	)	$	(8,516,931	)	$	(6,605,612	)	$	(16,855,925	)


	Three months ended September 30,					Nine months ended September 30,
	2011		2010			2011			2010
Derivatives in ASC 815-20-25 Cash Flow Hedging Relationships—Interest Rate Swaps

Location of Gain or (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)		Interest expense
Amount of Gain or (Loss) Recognized in OCI on Derivative (Effective Portion)	$	—	$	(28,185	)	$	(206	)	$	26,149

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

Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	$	—	$	(142,814	)	$	(17,782	)	$	(546,157	)

Accumulated other comprehensive loss of $1,309,211 as of September 30, 2011 consisted entirely of foreign currency translation adjustments.

Note 7—Asset Purchase Agreement

On October 14, 2011, the Company executed definitive agreements with a privately-held company to purchase proved developed and undeveloped coalbed methane (“CBM”) reserves and undeveloped leasehold acreage in Alabama and West Virginia, as well as certain natural gas derivative contracts, and a license to use a certain drilling technology. Total consideration for the acquired assets is estimated to be $90.2 million. The effective date used to calculate the purchase price is July 1, 2011 and is subject to customary closing conditions and purchase price adjustments.

The Company also entered into a Fifth Amended and Restated Credit Agreement to finance the asset purchase which will become effective upon the closing of the transaction described above. The key elements of this new credit agreement are described in Note 9—Long-Term Debt.

Acquisition costs of $370,621 related to this transaction have been recorded in the Consolidated Statements of Operations for the three and nine months ended September 30, 2011.

Note 8—Terminated Transaction Costs

Terminated transaction costs consist of payments made related to a terminated financing transaction between the Company and NGP Capital Resources Company (“NGPC”) and North Shore Energy, LLC (“North Shore”), an affiliate of Yorktown Energy Partners IV, L.P. (“Yorktown”) (Yorktown is a related party to the Company) and expenses related to a terminated sale of certain gas properties. There were no terminated transaction costs for the three and nine months ended September 30, 2011. The following is a detail of terminated transaction costs and related party amounts for the three and nine months ended September 30, 2010:


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

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

Note 9—Long-Term Debt

On September 14, 2010, our Fourth Amended and Restated Credit Agreement (the “Existing Credit Agreement”) with a group of five banks became effective. The Existing Credit Agreement replaced our Third Amended and Restated Credit Agreement and provides for revolving credit borrowings of up to $180 million with an initial borrowing base of $90 million. The borrowing base is determined as of each June and December. The June 2011 borrowing base determination was completed on April 15, 2011 and the borrowing base remains at $90 million. Also on April 15, 2011, the Existing Credit Agreement was amended to remove the minimum Fixed Charge Ratio covenant which was described in our Annual Report on Form 10-K. All outstanding borrowings under the Existing Credit Agreement become due and payable on September 14, 2013. The Existing Credit Agreement provides for interest to accrue at a rate calculated, at the Company’s option, at the Adjusted Base Rate plus a margin of 1.75% to 2.25% or the London

Interbank Offered Rate (the “LIBOR Rate”) rate plus a margin of 2.75% to 3.25%. Adjusted Base Rate is defined to be the greater of (i) the agent’s base rate or (ii) the federal funds rate plus one half of one percent or (iii) the LIBOR Rate plus a margin of 1.00%. In all cases the applicable margin is dependent on the percentage of borrowing base usage. Under the Existing Credit Agreement we are subject to certain financial covenants requiring maintenance of (i) a minimum Current Ratio, (ii) a maximum Debt Ratio, and (iii) a minimum Interest Coverage Ratio. The Current Ratio of consolidated current assets (defined to include amounts available under our borrowing base) to consolidated current liabilities (defined to exclude up to $1.5 million in accrued and unpaid preferred dividends and the effects, including associated deferred taxes, of unrealized derivative gains and losses) is not permitted to be less than 1.0 to 1.0 as of the end of any fiscal quarter. The Debt Ratio (defined as funded debt at the end of each fiscal quarter to trailing four quarter consolidated EBITDA) at the end of each fiscal quarter cannot exceed 4.0 to 1.0. The Interest Coverage Ratio (defined as consolidated EBITDA to consolidated net cash interest expense plus letter of credit fees accruing during the preceding four quarters) cannot be less than 2.75 to 1. Consolidated EBITDA is defined as earnings (loss) before deducting net interest expense, income taxes, depreciation, depletion and amortization and also excludes non-recurring charges and other non-cash charges deducted in determining net income (loss), which would include unrealized gains and losses from a change in the market value of open derivative contracts. We are also subject to covenants restricting or prohibiting cash dividends and other restricted payments, transactions with affiliates, incurrence of debt, consolidations and mergers, the level of operating leases, assets sales, investments in other entities, and liens on properties. Cash dividends on our preferred stock are permitted if, following any such cash payment our availability is equal to or greater than 15% of the then current borrowing base and our Debt Ratio is less than 3.5 to 1.0. There are no restrictions associated with dividends paid-in-kind on our preferred stock. At September 30, 2011, we are in compliance with the aforementioned Existing Credit Agreement covenants and expect to continue to be in compliance for at least the next 12 months.

On October 14, 2011, the Company entered into a Fifth Amended and Restated Credit Agreement (the “New Credit Agreement”) which will become effective upon the closing of the transaction described in Note 7—Asset Purchase Agreement. The key elements of the New Credit Agreement are (i) the notional amount of the credit agreement will be increased from $180 million to $250 million, (ii) the borrowing base will be increased from $90 million to $180 million, (iii) the group of lenders, with Bank of America, N.A. as Administrative Agent, BNP Paribas as Syndication Agent and US Bank National Association and Bank of Scotland plc as co-documentation agents, will be increased from five to six banks, (iv) the new credit facility will have a four year maturity, an extension of the Company’s current facility by more than two years, (v) the Company’s borrowing rate has been reduced by 50 basis points and certain financial and other covenants have been improved, and (vi) the Debt Ratio (defined as funded debt at the end of each fiscal quarter to trailing four quarter consolidated EBITDA) at the end of each fiscal quarter cannot exceed 4.25 to 1.0 through 2012 and cannot exceed 4.0 to 1.0 thereafter.

As of September 30, 2011, we had $81.0 million of borrowings outstanding under our Existing Credit Agreement, resulting in a borrowing availability of $9.0 million under our $90.0 million borrowing base, subject to compliance with covenants. For the three months ended September 30, 2011, we borrowed $8.5 million and made payments of $6.9 million under the Existing Credit Agreement. For the three months ended September 30, 2010, we borrowed $7.8 million and made payments of $44.3 million under the Existing Credit Agreement. For the nine months ended September 30, 2011, we borrowed $24.3 million and made payments of $23.8 million under the Existing Credit Agreement. For the nine months ended September 30, 2010, we borrowed $18.3 million and made payments of $58.3 million under the revolving credit facility. The rates at September 30, 2011 and December 31, 2010 were 3.54% and 3.30% per annum, respectively.

For the three months ended September 30, 2011 and 2010, interest on the borrowings averaged 3.45% per annum and 4.06% per annum, respectively. For the nine months ended September 30, 2011 and 2010, interest on the borrowings averaged 3.41% per annum and 3.69% per annum, respectively.

The following is a summary of our long-term debt at September 30, 2011 and December 31, 2010:


	September 30, 2011			December 31, 2010
Borrowings under Existing Credit Agreement	$	81,000,000		$	80,500,000
Note payable to a third party, annual installments of $53,000 through January 2011, interest-bearing at 8.25% annually, unsecured		—			48,961
Note payable to an individual, semi-monthly installments of $644, through September 2015, interest-bearing at 12.6% annually, unsecured		82,022			93,321
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		303,057			353,880

Total debt		81,385,079			80,996,162
Less current maturities included in current liabilities		(89,693	)		(132,743	)

Total long-term debt	$	81,295,386		$	80,863,419

The fair value of long-term debt at September 30, 2011 and December 31, 2010 was approximately $75.1 million and $68.4 million, respectively. ASC 820-10-55 clarifies that a fair value measurement for an asset or liability reflects its nonperformance risk, the risk that the obligation will not be fulfilled. Because nonperformance risk includes our credit risk, we have considered the effect of our credit risk on the fair value of the long-term debt. This consideration involved discounting our long-term debt based on the difference between the 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 our long-term debt.

Note 10—Common Stock

At September 30, 2011 and December 31, 2010, there were 39,973,810 and 39,758,484 shares, respectively, of common stock outstanding, both including 10,432 shares of treasury stock held by the Company. Also included in common stock outstanding at September 30, 2011 and December 31, 2010 were 293,166 and 292,512 shares of restricted stock, respectively.

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 12—Share-Based Awards.

For the three and nine months ended September 30, 2011, no shares and 5,265 shares, respectively, 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 April 5, 2011, we issued 113,208 shares of common stock to our independent directors, representing 50% of their 2011 annual retainer. Additionally, for the three and nine months ended September 30, 2011, no shares of restricted stock were forfeited. 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.

For the three and nine months ended September 30, 2010, 10,758 and 75,190 shares, respectively, of common stock were issued upon the exercise of stock options granted under our 2006 Long-Term Incentive Plan. During the same periods, no common stock was issued upon the exercise of stock options granted under our 2005 Stock Option Plan. On September 20, 2010, we issued 157,622 shares of common stock to our independent directors, representing 50% of their 2010 annual retainer. Additionally, for the three and nine months ended September 30, 2010, 1,256 and 66,194 shares of restricted stock, respectively, were forfeited. On March 24, 2010 and June 15, 2010, 300 shares and 386 shares of common stock, respectively, were purchased by us from two non-executive employees for the payment of $289 and $494, 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.

Note 11—Series A Convertible Redeemable Preferred Stock

At September 30, 2011 and December 31, 2010, 4,549,537 and 4,148,538 shares of preferred stock were issued and outstanding, respectively. At September 30, 2011, an additional 2,852,295 shares of our preferred stock are reserved exclusively for the payment of paid-in-kind dividends (“PIK dividends”). During the three months ended September 30, 2011, the Company declared and issued PIK dividends of 137,788 shares to the holders of preferred stock. Additionally, during the three months ended September 30, 2011, cash dividends of $792 were paid for fractional share dividends not paid-in-kind. During the nine months ended September 30, 2011, the Company declared and issued PIK dividends of 400,999 shares to the holders of preferred stock. Additionally, during the nine months ended September 30, 2011, cash dividends of $2,014 were paid for fractional share dividends not paid-in-kind.

The following table details the activity related to the preferred stock for the nine months ended September 30, 2011:


Balance at December 31, 2010	$	22,074,320
Accretion of Series A Convertible Redeemable Preferred Stock		1,308,519
PIK Dividends for Series A Convertible Redeemable Preferred Stock		4,009,990
Issuance costs and other		(130,111	)

Balance at September 30, 2011	$	27,262,718

The following table details the activity related to the preferred stock for the nine months ended September 30, 2010:


Balance at December 31, 2009	$	—
Issuance of Series A Convertible Redeemable Preferred Stock		40,000,000
Allocated to derivative liability		(18,378,517	)


Accretion of Series A Convertible Redeemable Preferred Stock		73,532
PIK Dividend accrual for Series A Convertible Redeemable Preferred Stock		137,046
Issuance costs and other		(1,211,664	)

Balance at September 30, 2010	$	20,620,397

Note 12—Share-Based Awards

As of September 30, 2011, 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, 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 September 30, 2011, we recorded a compensation expense accrual of $161,880 which was allocated as an addition of $6,593 to lease operating expense, an addition of $117,898 to general and administrative expense, and $37,389 was capitalized to gas properties. During the nine months ended September 30, 2011, we recorded a compensation expense accrual of $679,034 of which $26,756 was allocated to lease operating expense, $549,589 was allocated to general and administrative expenses, and $102,689 was capitalized to gas properties. The future compensation cost of all the outstanding awards is $988,722 which will be amortized over the vesting period of such stock options and restricted stock. The weighted average remaining useful life of the future compensation cost is 1.20 years.

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

For the three months ended September 30, 2011, no grants were made under the 2006 Plan. For the nine months ended September 30, 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

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 nine months ended September 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 September 30, 2011		1,611,264		$	1.10		3.4	$	4,175

Options exercisable at September 30, 2011		278,324		$	0.72		4.5	$	2,783

During the three months ended September 30, 2011, no incentive stock options were granted nor exercised. During the nine months ended September 30, 2011, 5,265 incentive stock options were exercised with an intrinsic value of $0.72 per option. During the nine months ended September 30, 2011, 593,079 incentive stock options were granted with a grant-date fair value of $1.04 per option.

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


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

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

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

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

Non-Qualified Stock Options

The table below summarizes non-qualified stock option activity for the nine months ended September 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 September 30, 2011		992,272		$	2.32		2.7	$	1,038

Options exercisable at September 30, 2011		808,000		$	2.60		2.0	$	—

During the three months ended September 30, 2011, no non-qualified stock options were granted or exercised. During the nine months ended September 30, 2011, no non-qualified stock options were exercised. During the nine months ended September 30, 2011, 80,472 non-qualified stock options were granted with a grant-date fair value of $1.04 per option.

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


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

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

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

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

Restricted Stock Awards

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


	Number of Shares			Weighted Average Value at Grant Date
Non-vested restricted stock at December 31, 2010		292,512		$	3.95
Vested		(97,762	)	$	4.07
Granted in Option Exchange		98,416		$	1.32

Non-vested restricted stock at September 30, 2011		293,166		$	3.03

During the three and nine months ended September 30, 2011, 45,872 and 97,762 shares of restricted stock, respectively, vested with a vesting date fair value of $0.88 and $1.20 per share, respectively.

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


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

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

During the three and nine months ended September 30, 2010, 132,492 shares of restricted stock were granted with a weighted average grant-date fair value of $0.88 per share. During the three months ended September 30, 2010, 1,708 shares of restricted stock vested with a vesting date fair value of $0.86 per share. During the nine months ended September 30, 2010, 85,470 shares of restricted stock vested with a vesting date fair value of $1.02 per share.

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.

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


	Number of Shares		Weighted Average Value at Grant Date
Non-vested restricted stock units at December 31, 2010		—	$	—
Granted		232,089	$	1.59

Non-vested restricted stock units at September 30, 2011		232,089	$	1.59

Note 13—Commitments and Contingencies

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

Lease Revenue Audit

The lessor from one of our leases recently completed a five year revenue audit where the examiner claims to have identified two exceptions. The first exception is related to compressor fuel deductions totaling $529,398 and the second exception is related to gas settlement pricing and still pending or to be determined. We have not received a formal letter claiming the exceptions but we believe these claims to be without merit and we expect to deny the exceptions if and when we receive a formal letter.

Environmental and Regulatory

As of September 30, 2011, 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 14—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 bases 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.

As of September 30, 2011 and December 31, 2010, the Company had available, to reduce future taxable income, a United States federal regular net operating loss (“NOL”) carryforward of approximately $122.8 million and $113.6 million, respectively. As of September 30, 2011 and December 31, 2010, the Company also had available, to reduce future taxable income, various state NOL carryforwards totaling approximately $130.9 million and $123.0 million, respectively.

ASC 740 requires the Company to recognize income tax benefits for loss carry forwards that have not previously been recorded. The tax benefits recognized must be reduced by a valuation allowance when it is more likely than not that the deferred tax asset will not be realized. The Company has a net deferred tax asset of $43.5 million and $46.0 million, respectively, as of September 30, 2011 and December 31, 2010, of which both include a recorded valuation allowance of $3.1 million. Our valuation allowances primarily relate to our Canadian operations where we do not believe it is more likely than not that we will recover our net deferred tax asset prior to expiration and have recorded a full valuation allowance as we currently have no proved reserves in Canada. In addition, we have recorded a valuation allowance for certain immaterial state net operating losses where the Company has ceased operations.

Our first material NOL carryforward expires in 2022 and the last one expires in 2030. We also consider the lengthy carryforward period in the overall evaluation of our ability to realize our NOLs as it substantially increases the likelihood of utilization.

In determining the carrying value of a deferred tax asset, ASC 740 provides for the weighing of 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 September 30, 2011 and December 31, 2010, the Company considered all available negative and positive evidence. While the Company has incurred a cumulative loss over the three year period ended September 30, 2011, after evaluating all available evidence

including historical operating results, historical pricing, current operating income, consideration of the full cost ceiling test impairments in 2009 and 2008 that resulted in the cumulative losses, our reserves level as estimated and appraised by an independent third party engineer, future pricing as indicated on the New York Mercantile Exchange, and the length of the carryforward period available, the Company concluded that it is more likely than not the deferred tax asset, net of the $3.2 million valuation allowance related to our Canadian operations and state NOLs, will be realized. The Company will continue to assess the need for additional valuation allowances in the future. If future results are less than projected using either our historical results or our forecast based on the reserve report and future market pricing, then additional valuation allowances may be required to reduce the deferred tax assets which could have a material impact on the Company’s results of operations in the period in which it is recorded.

For the three months ended September 30, 2011 and 2010, our effective tax rate was 40.0% and 45.7%, respectively. For the nine months ended September 30, 2011 and 2010, our effective tax rate was 39.0% and 44.8%, respectively. Our effective tax rates for the three and nine months ended September 30, 2011 were more than the combined estimated federal and state statutory rate of 38% primarily due to permanent differences related to our stock compensation, adjustments made to the current period expense related to the filing of our federal and state income tax returns for the year ended December 31, 2010, and the recording of a valuation allowance against the net income tax benefit related to our Canadian operations.

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 2010 Annual Report on Form 10-K that we filed with the SEC on April 6, 2011, 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, 2010, which are included in our 2010 Annual Report on Form 10-K that we filed with the SEC on April 6, 2011.

Overview

GeoMet, Inc. is an independent energy company primarily engaged in the exploration for and development and production of natural gas from coal seams (“coalbed methane” or “CBM”) and non-conventional shallow gas. We were originally founded as a consulting company to the coalbed methane industry in 1985 and have been active as an operator and developer of coalbed methane properties since 1993. Our principal operations and producing properties are located in the Cahaba Basin in Alabama and the central Appalachian Basin in West Virginia and Virginia. We also own additional coalbed methane and oil and gas development rights, principally in Alabama, British Columbia, Virginia, and West Virginia. As of September 30, 2011, we own a total of approximately 143,000 net acres of coalbed methane and oil and gas development rights.

Current Business Plan

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, proceeds from bank borrowings, and industry joint venture arrangements. 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, our ability to acquire, locate and produce new reserves, and events occurring within the global capital markets. We currently intend to drill our proved undeveloped locations in the Pond Creek field and on a limited basis in the Gurnee field to continue conducting hydraulic fracturing in new infill wells and in shallow behind pipe coal groups. Our current focus is to complete the asset purchase agreement described below, continue the developmental drilling program in the Pond Creek field, and, in the Gurnee field, improve production and determine the commerciality of future development through improved hydraulic fracturing techniques. The Company continues to consider strategic acquisition opportunities. At September 30, 2011 and December 31, 2010, we had $9.0 million and $9.5 million, respectively, in available borrowing capacity. This business plan is consistent with our past actions taken in unfavorable pricing environments. For example, when the price of natural gas declined precipitously at the end of 2008, we stopped substantially all of our development activities, and in 2009 did not drill any new wells.

Recent Developments

Asset Purchase Agreement

On October 14, 2011, the Company executed definitive agreements with a privately-held company to purchase proved developed and undeveloped CBM reserves and undeveloped leasehold acreage in Alabama and West Virginia, as well as certain natural gas derivative contracts, and a license to use a certain drilling technology. Total consideration for the acquired assets is estimated to be $90.2 million. The effective date used to calculate the purchase price is July 1, 2011 (the “Effective Date”) and is subject to customary closing conditions and purchase price adjustments.

Under the agreement, GeoMet will purchase (i) approximately 50 Bcf of estimated net proved CBM reserves (calculated in accordance with SEC guidelines) as of the Effective Date, (ii) net daily gas sales volumes which averaged approximately 22 MMcf per day for the first six months of 2011, (iii) natural gas derivative contracts totaling approximately 6.5 Bcf from the Effective Date through December 2012 with an average fixed price of $6.44/Mcf, (iv) a royalty free license to use a certain drilling technology in nine counties in West Virginia and one county in Virginia, and (v) approximately 70,000 net acres of undeveloped leasehold in West Virginia.

The Company also entered into a Fifth Amended and Restated Credit Agreement (the “New Credit Agreement”) to finance the asset purchase which will become effective upon the closing of the transaction described above. The key elements of the New Credit Agreement are described below in Liquidity and Capital Resources—Cash Flows and Liquidity.

Operational Developments

Pond Creek— For the three and nine months ended September 30, 2010, seven and eleven new wells, respectively, were added to sales. We have a total of 277 net producing wells in the Pond Creek field. For the three and nine months ended September 30, 2011, net gas sales volumes were 15.6 MMcf per day and 15.2 MMcf per day, respectively. For the three and nine months ended September 30, 2010, net gas sales volumes were 14.7 MMcf per day and 14.5 MMcf per day, respectively. We have successfully drilled 15 of the 16 planned wells for 2011. We revised the number of wells we plan to drill in the Pond Creek field during 2011 from 20 to 16, which reduced our budgeted capital expenditures in the field by $2.0 million. We allocated this $2.0 million to capital expenditures in our Gurnee field, as discussed below.

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 from 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 NYMEX contract for the month of sale plus $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. Additionally, we fixed the NYMEX settle on a portion of the aforementioned forward sale as follows: (1) 4,000 MMBtu/day for the period April 2011 through October 2011 was fixed at a total price for physical gas sales, including the aforementioned basis, of $4.915/MMBtu and (2) 3,000 MMBtu/day for the period November 2011 through March 2012 was fixed at a total price for physical gas sales, including the aforementioned basis, of $5.33/MMBtu. If we are unable to fulfill our commitment, or a portion thereof, we are obligated to reimburse our counterparty for any price paid to replace the quantity of natural gas we failed to deliver which is in excess of the contract price. This obligation is limited to the spot price for natural gas at the delivery point on the day we fail to deliver.

Gurnee—For the three and nine months ended September 30, 2011, production remained flat at 4.9 MMcf per day from a total of 222 producing wells in the Gurnee field. For the three and nine months ended September 30, 2010, net gas sales volumes were 4.9 MMcf per day and 5.1 MMcf per day, respectively. Our new hydraulic fracturing technique has been applied to 5 new full wellbores and 5 shallow completions in existing wellbores and these completions have resulted in production gains of approximately 1.0 MMcf per day and are continuing to incline. The total cost of these operations has been approximately $4 million. This has resulted in production rates approximately 5 times the field wide average on a foot of coal completed basis. Although warranting continued testing at this early stage, the economics of are not sufficient in the current price environment to support full scale development. We expect to test this technique in the undeveloped portion of the field on the west side of the Cahaba River where we hold approximately 17,000 acres of leasehold.

Lasher—No new wells were added to sales in the three and nine months ended September 30, 2011. For the three and nine months ended September 30, 2011, net gas sales volumes were 0.45 MMcf per day and 0.44 MMcf per day, respectively, from 18 producing wells. For the three and nine months ended September 30, 2010, net gas sales volumes were 0.41 MMcf per day and 0.39 MMcf per day, respectively.

Garden City—We put our two horizontal wells back on production and reinstalled a compressor to sell the produced gas in the second quarter of 2011. However, we recently shut-in our two horizontal wells due to the current low gas price environment. At this time, we are evaluating our options.

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 nine months ended September 30, 2011.

Producing Fields Operations Summary

The table below presents information on gas sales, net sales volumes, production expenses and per Mcf data for the three and nine months ended September 30, 2011 and 2010. This table should be read in conjunction with the discussion of the results of operations for the periods presented below (in thousands).


	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
Gas sales	$	8,520	$	8,239	$	24,702	$	25,784
Lease operating expense	$	3,019	$	2,877	$	8,871	$	8,798
Compression and transportation expenses		1,084		1,096		2,965		3,175
Production taxes		390		227		1,078		723

Total production expenses	$	4,493	$	4,200	$	12,914	$	12,696
Net sales volumes (MMcf)		1,940		1,845		5,619		5,490
Pond Creek field		1,439		1,349		4,148		3,962
Gurnee field		453		455		1,330		1,396
Per Mcf data ($/Mcf):
Average natural gas sales price	$	4.39	$	4.47	$	4.40	$	4.70
Average natural gas sales price realized(1)	$	5.26	$	5.45	$	5.59	$	5.70
Lease operating expense	$	1.56	$	1.56	$	1.58	$	1.60
Pond Creek field	$	1.13	$	1.17	$	1.17	$	1.25
Gurnee field	$	2.76	$	2.54	$	2.74	$	2.31
Compression and transportation expenses	$	0.56	$	0.60	$	0.53	$	0.58
Pond Creek field	$	0.60	$	0.65	$	0.56	$	0.63
Gurnee field	$	0.39	$	0.45	$	0.36	$	0.40
Production taxes	$	0.20	$	0.12	$	0.19	$	0.13
Pond Creek field	$	0.21	$	0.16	$	0.19	$	0.17
Gurnee field (2)	$	0.20	$	0.01	$	0.21	$	0.05
Total production expenses	$	2.32	$	2.28	$	2.30	$	2.31
Pond Creek field	$	1.94	$	1.98	$	1.92	$	2.05
Gurnee field	$	3.35	$	3.00	$	3.31	$	2.76
Depreciation, depletion and amortization	$	0.97	$	0.85	$	0.92	$	0.85

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

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

Results of Operations

Three months ended September 30, 2011 compared with three months ended September 30, 2010

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


	Three months ended September 30,
	2011			2010			Change
	(In thousands)
Gas sales	$	8,520		$	8,239			3	%
Lease operating expense	$	3,019		$	2,877			5	%
Compression expense	$	759		$	777			-2	%
Transportation expense	$	325		$	319			2	%
Production taxes	$	390		$	227			72	%
Depreciation, depletion and amortization	$	1,888		$	1,561			21	%
General and administrative	$	1,158		$	1,206			-4	%
Acquisition costs	$	371		$	—			NM
Realized gains on natural gas derivative contracts	$	(1,682	)	$	(1,825	)		NM
Unrealized gains on natural gas derivative contracts	$	(2,544	)	$	(5,096	)		NM
Interest expense	$	869		$	1,510			-42	%
Unrealized gain from change in fair value derivative liability – Series A Convertible Redeemable Preferred Stock	$	—		$	(1,596	)		NM
Income tax expense	$	1,620		$	3,813			NM

NM - Not Meaningful

Gas sales. Gas sales increased by $0.28 million, or 3%, to $8.52 million compared to the prior year quarter. The increase in gas sales was a result of increased production volumes partially offset by decreased gas prices. Average gas prices decreased 2%, excluding hedging transactions, and production increased 5% from the prior year quarter. The increase in production was primarily due to the resumption of drilling activities and the addition of new wells to sales during the current year quarter.

Lease operating expense. Lease operating expense increased by $0.14 million, or 5%, to $3.02 million compared to the prior year quarter. The $0.14 million increase consisted of a $0.15 million increase in production partially offset by a $0.01 million decrease in costs. The increase in production was primarily due to the resumption of drilling activities and the addition of new wells to sales during the current year quarter.

Compression expense. Compression expense decreased by $0.02 million, or 2%, to $0.76 million compared to the prior year quarter. The $0.02 million decrease was comprised of a $0.06 million decrease in costs partially offset by a $0.04 million increase in production. The decrease in costs was primarily due to the exercise of early buyout options on two leased compressors in November 2010.

Transportation expense. Transportation expense remained flat compared to the prior year quarter.

Production taxes. Production taxes increased by $0.16 million, or 72%, to $0.39 million compared to the prior year quarter. The $0.16 million increase in production taxes was primarily due to effect of diminishing tax exemptions in West Virginia in conjunction with increased volumes resulting from the addition of new wells to sales during the current year quarter.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $0.33 million, or 21%, to $1.89 million compared to the prior year quarter. The depreciation, depletion and amortization increase consisted of a $0.08 million increase in production and a $0.25 million increase in the depletion rate. Depletion for the three months ended September 30, 2011 and 2010 was $0.93 and $0.78 per Mcf, respectively. The increase in the depletion rate was due to a decreased natural gas reserve base caused by lower natural gas prices in the current year.

General and administrative. General and administrative expenses decreased by $0.05 million, or 4%, to $1.16 million compared to the prior year quarter. The decrease was primarily due to decreased cost related to our share-based awards as compared to the prior year quarter.

Acquisition costs. Acquisition costs were related to the agreement to purchase CBM assets in Alabama and West Virginia.

Realized gains on natural gas derivative contracts. Realized gains on natural gas derivative contracts were $1.68 million in the current year quarter as compared to $1.82 million in the prior year quarter. Realized losses represent net cash flow settlements paid to the counterparty, while realized gains represent net cash flow settlements paid to us from the counterparty. Realized losses occur when natural gas prices exceed the derivative ceiling prices. Conversely, realized gains occur when natural gas prices go below the derivative floor prices.

Unrealized gains on natural gas derivative contracts. Unrealized gains on natural gas derivative contracts were $2.54 million in the current year quarter. 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. The unrealized gains were a combined result of a $4.2 million increase in the fair value of open natural gas derivative contracts caused by changes in NYMEX natural gas futures, partially offset by a $1.7 million decrease resulting from the settlement or expiration of natural gas derivative contracts during the period.

Interest expense. Interest expense decreased by $0.64 million, or 42%, to $0.87 million compared to the prior year period. The decrease was primarily due to a lower average outstanding revolver balance and a lower average borrowing rate in the current year quarter.

Unrealized gain from change in fair value of derivative liability – Series A Convertible Redeemable Preferred Stock. In the prior year quarter, an unrealized gain was recorded to reflect the decrease in the market price of our stock from the issuance date of our Series A Convertible Redeemable Preferred Stock of September 14, 2010 through the end of the prior year quarter. On December 21, 2010, the Company amended the terms of the anti-dilution provisions of its preferred stock. The effect of the amendment was to extinguish the derivative liability and reclassify it to paid-in capital. Since the effective date of the aforementioned amendment, no such gains or losses have been recognized relative to the anti-dilution provisions of our preferred stock. Therefore, no such gain was recorded in the current year quarter.

Income tax expense. For the three months ended September 30, 2011 and 2010, our effective tax rate was 40.0% and 45.7%, respectively. Our effective tax rate for the three months ended September 30, 2011 was more than the combined estimated federal and state statutory rate of 38% primarily due to permanent differences related to our stock compensation, adjustments made to the current period expense related to the filing of our federal and state income tax returns for the year ended December 31, 2010, and the recording of a valuation allowance against the net income tax benefit related to our Canadian operations.

Nine months ended September 30, 2011 compared with nine months ended September 30, 2010

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


	Nine months ended September 30,
	2011			2010			Change
	(In thousands)
Gas sales	$	24,702		$	25,784			-4	%
Lease operating expense	$	8,871		$	8,798			1	%
Compression expense	$	2,010		$	2,219			-9	%
Transportation expense	$	956		$	957			0	%
Production taxes	$	1,078		$	723			49	%
Depreciation, depletion and amortization	$	5,142		$	4,657			10	%
General and administrative	$	4,100		$	3,999			3	%
Acquisition costs	$	371		$	—			NM
Terminated transaction costs	$	—		$	1,403			-100	%
Realized gains on natural gas derivative contracts	$	(6,715	)	$	(5,496	)		NM
Unrealized losses (gains) on natural gas derivative contracts	$	109		$	(9,764	)		NM
Interest expense	$	2,532		$	4,178			-39	%
Unrealized gain from change in fair value derivative liability – Series A Convertible Redeemable Preferred Stock	$	—		$	(1,596	)		NM
Income tax expense	$	2,527		$	7,136			NM

NM - Not Meaningful

Gas sales. Gas sales decreased by $1.08 million, or 4%, to $24.70 million compared to the prior year period. The decrease in gas sales was a result of decreased gas prices partially offset by increased production. Average gas prices decreased 6%, excluding hedging transactions. Production increased 2% from the prior year period despite net gas sales volumes for the period being reduced by approximately 0.2 MMcf per day as a result of a temporary reduction in pipeline delivery capacity resulting from a mechanical accident at one of our compressor stations in our Pond Creek field.

Lease operating expense. Lease operating expense remained flat relative to gas sales compared to the prior year period.

Compression expense. Compression expense decreased by $0.21 million, or 9%, to $2.01 million compared to the prior year period. The $0.21 million decrease was comprised of a $0.26 million decrease in costs partially offset by a $0.05 million increase in production. The $0.26 million decrease in costs was primarily due to the exercise of early buyout options on two leased compressors in November 2010.

Transportation expense. Transportation expense remained flat compared to the prior year period.

Production taxes. Production taxes increased by $0.35 million, or 49%, to $1.08 million compared to the prior year period. The $0.35 million increase in production taxes was primarily due to a refund received in March 2010 for production taxes related to our Gurnee field offset by diminishing tax exemptions in West Virginia in conjunction with increased volumes resulting from the addition of new wells to sales during the current year period.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $0.49 million, or 10%, to $5.14 million compared to the prior year period. The depreciation, depletion and amortization increase consisted of a $0.11 million increase in production and a $0.38 million increase in the depletion rate. Depletion for the nine months ended September 30, 2011 and 2010 was $0.86 and $0.78 per Mcf, respectively. The increase in the depletion rate was due to a decreased natural gas reserve base caused by lower natural gas prices in the current year.

General and administrative. General and administrative expenses increased by $0.10 million, or 3%, to $4.10 million compared to the prior year period. The $0.10 million increase was primarily due to increased professional fees.

Acquisition costs. Acquisition costs were related to the agreement to purchase CBM assets in Alabama and West Virginia.

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

Realized gains on natural gas derivative contracts. Realized gains on natural gas derivative contracts were $6.71 million in the current year period as compared to $5.50 million in the prior year period. Realized losses represent net cash flow settlements paid to the counterparty, while realized gains represent net cash flow settlements paid to us from the counterparty. Realized losses occur when natural gas prices exceed the derivative ceiling prices. Conversely, realized gains occur when natural gas prices go below the derivative floor prices.

Unrealized losses (gains) on natural gas derivative contracts. Unrealized losses on natural gas derivative contracts were $0.11 million in the current period. 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. The unrealized losses were a combined result of a $6.6 million increase in the fair value of open natural gas derivative contracts caused by changes in NYMEX natural gas futures, offset by a $6.7 million decrease resulting from the settlement or expiration of natural gas derivative contracts during the period.

Interest expense. Interest expense decreased by $1.65 million, or 39%, to $2.53 million compared to the prior year period. The decrease was primarily due to a lower average outstanding revolver balance and a lower average borrowing rate in the current year period.

Unrealized gain from change in fair value of derivative liability – Series A Convertible Redeemable Preferred Stock. In the prior year period, an unrealized gain was recorded to reflect the decrease in the market price of our stock from the issuance date of our Series A Convertible Redeemable Preferred Stock of September 14, 2010 through the end of the prior year period. On December 21, 2010, the Company amended the terms of the anti-dilution provisions of its preferred stock. The effect of the amendment was to extinguish the derivative liability and reclassify it to paid-in capital. Since the effective date of the aforementioned amendment, no such gains or losses have been recognized relative to the anti-dilution provisions of our preferred stock. Therefore, no such gain was recorded in the current year period.

Income tax expense. For the nine months ended September 30, 2011 and 2010, our effective tax rate was 39.0% and 44.8%, respectively. Our effective tax rate for the nine months ended September 30, 2011 was more than the combined estimated federal and state statutory rate of 38% primarily due to permanent differences related to our stock compensation, adjustments made to the current period expense related to the filing of our federal and state income tax returns for the year ended December 31, 2010, and the recording of a valuation allowance against the net income tax benefit related to our Canadian operations.

Liquidity and Capital Resources

Cash Flows and Liquidity

Cash flows provided by operations for the nine months ended September 30, 2011 and 2010 were $11.6 million and $11.7 million, respectively. As of September 30, 2011, we had working capital of approximately $1.7 million. As of December 31, 2010, we had working capital of approximately $1.5 million. Cash provided by operating activities of $11.6 million, cash provided by financing activities of $0.2 million and $0.1 million of our cash on hand were used to fund our investing activities of $11.9 million, which primarily includes capital expenditures for the development of our gas properties.

Additionally, based upon current expectations, we believe that our cash flow from operations and other financial resources such as borrowings under the Existing Credit Agreement and/or New Credit Agreement will provide us with sufficient capital resources to meet our projected operational and capital expenditure needs for the next twelve months.

Excluding our recently announced asset purchase agreement, our capital budget has been increased to $14.4 million for the year ending December 31, 2011. We expect our remaining capital expenditure budget, excluding the aforementioned asset purchase agreement, for 2011 of $0.8 million to be funded from our estimated operating cash flows. The amount and timing of our expenditures are subject to change based upon market conditions, natural gas prices, results of operations and other factors. We routinely adjust our capital expenditure budget in response to changes in natural gas prices, drilling and acquisition costs, cash flow, drilling results and changes in borrowing capacity under our Existing Credit Agreement. Upon closing of the aforementioned asset purchase agreement, cash flow from operations will also be used for debt reduction.

On September 14, 2010, our Existing Credit Agreement with a group of five banks became effective. The Existing Credit Agreement replaced our Third Amended and Restated Credit Agreement and provides for revolving credit borrowings of up to $180 million with an initial borrowing base of $90 million. The borrowing base is determined as of each June and December. The June 2011 borrowing base determination was completed on April 15, 2011 and the borrowing base remains at $90 million. Also on April 15, 2011, the Existing Credit Agreement was amended to remove the minimum Fixed Charge Ratio covenant which was described in our Annual Report on Form 10-K. All outstanding borrowings under the Existing Credit Agreement become due and payable on September 14, 2013. The Existing Credit Agreement provides for interest to accrue at a rate calculated, at the Company’s option, at the Adjusted Base Rate plus a margin of 1.75% to 2.25% or the London Interbank Offered Rate (the “LIBOR Rate”) rate plus a margin of 2.75% to 3.25%. Adjusted Base Rate is defined to be the greater of (i) the agent’s base rate or (ii) the federal funds rate plus one half of one percent or (iii) the LIBOR Rate plus a margin of 1.00%. In all cases the applicable margin is dependent on the percentage of borrowing base usage. Under the Existing Credit Agreement we are subject to certain financial covenants requiring maintenance of (i) a minimum Current Ratio, (ii) a maximum Debt Ratio, and (iii) a minimum Interest Coverage Ratio. The Current Ratio of consolidated current assets (defined to include amounts available under our borrowing base) to consolidated current liabilities (defined to exclude up to $1.5 million in accrued and unpaid preferred dividends and the effects, including associated deferred taxes, of unrealized derivative gains and losses) is not permitted to be less than 1.0 to 1.0 as of the end of any fiscal quarter. The Debt Ratio (defined as funded debt at the end of each fiscal quarter to trailing four quarter consolidated EBITDA) at the end of each fiscal quarter cannot exceed 4.0 to 1.0. The Interest Coverage Ratio (defined as consolidated EBITDA to consolidated net cash interest expense plus letter of credit fees accruing during the preceding four quarters) cannot be less than 2.75 to 1. Consolidated EBITDA is defined as earnings (loss) before deducting net interest expense, income taxes, depreciation, depletion and amortization and also excludes non-recurring charges and other non-cash charges deducted in determining net income (loss), which would include unrealized gains and losses from a change in the market value of open derivative contracts. We are also subject to covenants restricting or prohibiting cash dividends and other restricted payments, transactions with affiliates, incurrence of debt, consolidations and mergers, the level of operating leases, assets sales, investments in other entities, and liens on properties. Cash dividends on our preferred stock are permitted if, following any such cash payment our availability is equal to or greater than 15% of the then current borrowing base and our Debt Ratio is less than 3.5 to 1.0. There are no restrictions associated with dividends paid-in-kind on our preferred stock. At September 30, 2011, we are in compliance with the aforementioned Existing Credit Agreement covenants and expect to continue to be in compliance for at least the next 12 months.

On October 14, 2011, the Company entered into the New Credit Agreement which will become effective upon the closing of the transaction described above in Recent Developments—Asset Purchase Agreement. The key elements of the New Credit Agreement are (i) the notional amount of the credit agreement will be increased from $180 million to $250 million, (ii) the borrowing base will be increased from $90 million to $180 million, (iii) the group of lenders, with Bank of America, N.A. as Administrative Agent, BNP Paribas as Syndication Agent and US Bank National Association and Bank of Scotland plc as co-documentation agents, will be increased from five to six banks, (iv) the new credit facility will have a four year maturity, an extension of the Company’s current facility by more than two years, and (v) the Company’s borrowing rate has been reduced by 50 basis points and certain financial and other covenants have been improved, and (vi) the Debt Ratio (defined as funded debt at the end of each fiscal quarter to trailing four quarter consolidated EBITDA) at the end of each fiscal quarter cannot exceed 4.25 to 1.0 through 2012 and cannot exceed 4.0 to 1.0 thereafter.

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

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

Price Risk Management Activities

At September 30, 2011, we had no natural gas collar positions.

At September 30, 2011, we had the following natural gas swap positions:


Period	Volume (MMBtu)		Fixed Price		Fair Value
October 2011		124,000	$	6.37		323,761
October 2011		124,000	$	5.37		199,142
October 2011		124,000	$	5.43		207,202
November 2011 through March 2012		608,000	$	7.12		1,894,183
November 2011 through March 2012		608,000	$	6.12		1,283,872
November 2011 through March 2012		912,000	$	5.08		983,019
April through October 2012		856,000	$	5.73		1,308,794
April through October 2012		1,712,000	$	4.94		1,262,519
November 2012 through March 2013		604,000	$	6.42		1,010,165
November 2012 through March 2013		906,000	$	5.50		692,623

		6,578,000			$	9,165,280

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 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.

As of September 30, 2011, we 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
October 2011		124,000	$	4.80	$	0.115	$	4.915	$	609,460
November 2011 through March 2012		456,000	$	5.20	$	0.130	$	5.330		2,430,480

		580,000							$	3,039,940

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


Period	Volume (MMBtu)		Fixed Basis Differential
October 2011		372,000	$	0.115
November 2011 through March 2012		1,976,000	$	0.130

		2,348,000

Capital Expenditures and Capital Resources

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


	Three Months Ended September 30,				Nine months Ended September 30,
	2011		2010		2011		2010
Capital expenditures:
Leasehold acquisition	$	154,072	$	155,708	$	689,790	$	349,436
Exploration		—		—		3,000		3,115
Development		4,472,521		3,127,937		11,976,251		7,378,918
Other items (primarily capitalized overhead and interest)		362,605		270,067		902,986		659,729

Total capital expenditures	$	4,989,198	$	3,553,712	$	13,572,027	$	8,391,198

Our capital budget, excluding the aforementioned asset purchase agreement, has been increased to $14.4 million for the year ending December 31, 2011. In March 2011, we reallocated $2.0 million from the Pond Creek field to the Gurnee field to increase our hydraulic fracturing testing activities in Gurnee. We expect our remaining capital expenditure budget, excluding the aforementioned asset purchase agreement, for 2011 of $0.8 million to be funded from our estimated operating cash flows. If the amount and timing of cash flows are reduced, we will reduce our capital budget. We expect the purchase price related to the asset purchase agreement to be approximately $90.2 million which we plan to finance through borrowings under the New Credit Agreement. Due to closing late in the year, we do not expect to make substantial capital expenditures on those assets during 2011. The amount and timing of our expenditures are subject to change based upon market conditions, natural gas prices, results of expenditures and other factors. We routinely adjust our capital expenditure budget in response to changes in natural gas prices, drilling and acquisition costs, cash flow, drilling results, borrowing base redeterminations under our Existing Credit Agreement and/or New Credit Agreement, and other available investment opportunities.

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 2010 Annual Report on Form 10-K that we filed with the SEC on April 6, 2011.

Recent Pronouncements

In December 2010, the FASB issued ASU No. 2010-29, Disclosure of Supplementary Pro Forma Information for Business Combinations (ASU 2010-29). ASU 2010-29 requires a public entity who discloses comparative pro forma information for business combinations that occurred in the current reporting period to disclose revenue and earnings of the combined entity as though the business combination(s) occurred as of the beginning of the comparable prior annual period only. This update also expands the supplemental pro forma disclosures required to include a description of the nature and amount of material, nonrecurring pro forma

adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. ASU 2010-29 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010 and early adoption is permitted. The Company will apply the provisions of this update for any business combinations that occur after January 1, 2011.

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 nine months ended September 30, 2011, a 10% decrease in the prices received for natural gas production would have decreased our gas revenues by approximately $0.9 million and $2.5 million, respectively, which would have been offset approximately $0.5 million and $1.5 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 September 30, 2011, we had $81.0 million outstanding under our Existing Credit Agreement. For the three months ended September 30, 2011 and 2010, interest on the borrowings averaged 3.45% per annum and 4.06% per annum, respectively. For the nine months ended September 30, 2011 and 2010, interest on the borrowings averaged 3.41% per annum and 3.69% per annum, respectively. Borrowing availability at September 30, 2011 was $9.0 million. All of the debt outstanding under our Existing 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 Existing Credit Agreement, a 1% increase in market interest rates would have increased interest expense and negatively impacted our cash flows for the three and nine months ended September 30, 2011 by approximately $0.2 million and $0.6 million, respectively.

Foreign Currency Exchange Rate Risk. We have exploratory operations in Canada and do not have operations in any other foreign countries. We do not hedge our foreign currency risk and are exposed to foreign currency exchange rate risk in the Canadian dollar. We continue to monitor the foreign currency exchange rate in Canada and may implement measures to protect against the foreign currency exchange rate risk in the future.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2011 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.

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

Lease Revenue Audit

Environmental and Regulatory

As of September 30, 2011, 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 the following update to the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2010:

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

Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions but is not subject to regulation at the federal level. The U.S. Environmental Protection Agency has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. In addition, if hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. In addition, restrictions on hydraulic fracturing could reduce the amount of natural gas that we are ultimately able to produce in commercial quantities.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. [Removed and Reserved]

Item 5. Other Information

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.

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.

INDEX TO EXHIBITS


Exhibit Number		Exhibits

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.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company