GMX Resources (GMXRW) 10-Q 2010 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2010

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

For the transition period from            to            

Commission File Number 001-32977

GMX RESOURCES INC.

(Exact name of registrant as specified in its charter)

Oklahoma	73-1534474
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)
One Benham Place, 9400 North Broadway, Suite 600 Oklahoma City, Oklahoma	73114
(Address of principal executive offices)	(Zip Code)

(Registrants’ telephone number, including area code): (405) 600-0711

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.    Yes  x    No  ¨

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

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

Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

The number of shares outstanding of the registrant’s common stock as of August 2, 2010 was 30,901,620, which included 2,640,000 shares under a share loan which will be returned to the registrant upon conversion of certain outstanding convertible notes.

GMX Resources Inc.

Form 10-Q

For the Quarter Ended June 30, 2010

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION		1
ITEM 1.	Financial Statements	1
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	15
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	20
ITEM 4.	Controls and Procedures	22
PART II. OTHER INFORMATION		22
ITEM 1.	Legal Proceedings	22
ITEM 1A.	Risk Factors	22
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	22
ITEM 3.	Defaults Upon Senior Securities	23
ITEM 4.	Removed and Reserved	23
ITEM 5.	Other Information	23
ITEM 6.	Exhibits	23
SIGNATURES		24
EXHIBIT INDEX		25

i

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

GMX Resources Inc. and Subsidiaries

Consolidated Balance Sheets

(dollars in thousands, except share data)

(Unaudited)

	December 31, 2009			June 30, 2010
	(as adjusted)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	35,554		$	3,125
Accounts receivable – interest owners		1,233			3,936
Accounts receivable – oil and natural gas revenues, net		9,340			7,297
Derivative instruments		12,252			16,380
Inventories		326			326
Prepaid expenses and deposits		4,506			4,948
Total current assets		63,211			36,012
OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD
Properties being amortized		756,412			825,607
Properties not subject to amortization		39,789			51,963
Less accumulated depreciation, depletion, and impairment		(464,872	)		(477,636	)
		331,329			399,934
PROPERTY AND EQUIPMENT, AT COST, NET		101,755			104,563
DERIVATIVE INSTRUMENTS		17,292			19,683
OTHER ASSETS		8,484			6,383
TOTAL ASSETS	$	522,071		$	566,575
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	19,180		$	17,514
Accrued expenses		12,907			21,336
Accrued interest		3,361			3,350
Revenue distributions payable		4,434			5,443
Current maturities of long-term debt		48			48
Total current liabilities		39,930			47,691
LONG-TERM DEBT, LESS CURRENT MATURITIES		190,230			218,582
DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS		16,299			14,740
OTHER LIABILITIES		7,151			7,218
EQUITY:
Preferred stock, par value $.001 per share, 10,000,000 shares authorized:
Series A Junior Participating Preferred Stock 25,000 shares authorized, none issued and outstanding		—			—
9.25% Series B Cumulative Preferred Stock, 3,000,000 Shares authorized, 2,000,000 shares issued and outstanding (aggregate liquidation preference $50,000,000)		2			2
Common stock, par value $.001 per share – 100,000,000 shares authorized, 31,214,968 shares issued and outstanding in 2009 and 30,901,620 shares issued and outstanding in 2010		31			31
Additional paid-in capital		522,645			526,695
Accumulated deficit		(284,745	)		(283,906	)
Accumulated other comprehensive income, net of taxes		8,447			13,465
Total GMX Resources’ equity		246,380			256,287
Noncontrolling interest		22,081			22,057
Total equity		268,461			278,344
TOTAL LIABILITIES AND EQUITY	$	522,071		$	566,575

See accompanying notes to consolidated financial statements.

1

GMX Resources Inc. And Subsidiaries

Consolidated Statements of Operations

(dollars in thousands, except share and per share data)

(Unaudited)

	Three Months Ended June  30,						Six Months Ended June  30,
	2009			2010			2009			2010
	(as adjusted)						(as adjusted)
OIL AND GAS SALES, net of gain or (loss) from ineffectiveness of derivatives of $188, $(1,786), $992, and $(1,257), respectively	$	22,837		$	23,213		$	45,663		$	44,513
EXPENSES:
Lease operations		2,719			2,243			5,872			5,354
Production and severance taxes		307			315			(1,353	)		1,025
Depreciation, depletion, and amortization		6,641			8,731			15,501			15,101
Impairment of oil and natural gas properties		—			—			138,078			—
General and administrative		5,324			6,219			9,769			13,406
Total expenses		14,991			17,508			167,867			34,886
Income (loss) from operations		7,846			5,705			(122,204	)		9,627
NON-OPERATING INCOME (EXPENSES):
Interest expense		(4,095	)		(4,654	)		(8,151	)		(8,883	)
Interest and other income		14			9			33			33
Unrealized gains (losses) on derivatives		(1,028	)		107			(1,371	)		(114	)
Total non-operating expense		(5,109	)		(4,538	)		(9,489	)		(8,964	)
Income (loss) before income taxes		2,737			1,167			(131,693	)		663
PROVISION (BENEFIT) FOR INCOME TAXES		2,953			2,369			525			(3,419	)
NET INCOME (LOSS)		(216	)		(1,202	)		(132,218	)		4,082
Net income attributable to noncontrolling interest		—			618			—			931
NET INCOME (LOSS) ATTRIBUTABLE TO GMX RESOURCES		(216	)		(1,820	)		(132,218	)		3,151
Preferred stock dividends		1,157			1,157			2,313			2,313
NET INCOME (LOSS) APPLICABLE TO COMMON SHAREHOLDERS	$	(1,373	)	$	(2,977	)	$	(134,531	)	$	838
EARNINGS (LOSS) PER SHARE – Basic	$	(0.08	)	$	(0.11	)	$	(8.03	)	$	0.03
EARNINGS (LOSS) PER SHARE – Diluted	$	(0.08	)	$	(0.11	)	$	(8.03	)	$	0.03
WEIGHTED AVERAGE COMMON SHARES – Basic		18,093,208			28,181,587			16,746,112			28,140,319
WEIGHTED AVERAGE COMMON SHARES – Diluted		18,093,208			28,181,587			16,746,112			28,140,319

See accompanying notes to consolidated financial statements.

2

GMX Resources Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(dollars in thousands)

(Unaudited)

	Six Months Ended June  30,
	2009			2010
	(as adjusted)
CASH FLOWS DUE TO OPERATING ACTIVITIES
Net income (loss)	$	(132,218	)	$	4,082
Depreciation, depletion, and amortization		15,501			15,101
Impairment and other writedowns		138,078			—
Deferred income taxes		525			(3,389	)
Non-cash compensation expense		2,282			3,545
Non-cash interest expense		2,462			4,545
Other		866			1,371
Decrease (increase) in:
Accounts receivable		2,684			(659	)
Inventory and prepaid expenses		518			(79	)
Increase (decrease) in:
Accounts payable and accrued liabilities		(7,935	)		(2,340	)
Revenue distributions payable		(2,185	)		293
Net cash provided by operating activities		20,578			22,470
CASH FLOWS DUE TO INVESTING ACTIVITIES
Purchase of oil and natural gas properties		(92,476	)		(76,794	)
Proceeds from sale of oil and natural gas properties		—			4,656
Purchase of property and equipment		(19,914	)		(6,773	)
Proceeds from sale of property and equipment		—			1,330
Net cash used in investing activities		(112,390	)		(77,581	)
CASH FLOW DUE TO FINANCING ACTIVITIES
Advances on borrowings		85,000			26,000
Payments on debt		(55,036	)		(50	)
Proceeds from sale of common stock		65,347			—
Dividends paid on Series B preferred stock		(2,313	)		(2,312	)
Fees paid related to financing activities		(2,832	)		—
Other		—			(956	)
Net cash provided by financing activities		90,166			22,682
NET DECREASE IN CASH		(1,646	)		(32,429	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		6,716			35,554
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	5,070		$	3,125
SUPPLEMENTAL CASH FLOW DISCLOSURE
CASH PAID DURING THE PERIOD FOR:
INTEREST, Net of amounts capitalized	$	6,307		$	5,466
INCOME TAXES, Paid (Received)	$	—		$	(30	)

See accompanying notes to consolidated financial statements.

3

GMX Resources Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income

(dollars in thousands)

(Unaudited)

	Three Months Ended June  30,						Six Months Ended June  30,
	2009			2010			2009			2010
	(as adjusted)						(as adjusted)
Net income (loss)	$	(216	)	$	(1,202	)	$	(132,218	)	$	4,082
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative instruments, net of income tax of $(345), $122, $5,603, and $6,313, respectively		(670	)		237			10,876			12,254
Reclassification of (gain) loss on settled contracts, net of income tax of $(2,609), $(2,491), $(5,470), and $(3,728), respectively		(5,065	)		(4,834	)		(10,618	)		(7,236	)
Other comprehensive income (loss), net of income tax		(5,735	)		(4,597	)		258			5,018
Comprehensive income attributable to the noncontrolling interest		—			618			—			931
Comprehensive income (loss) attributable to GMX Resources Shareholders	$	(5,951	)	$	(6,417	)	$	(131,960	)	$	8,169

See accompanying notes to consolidated financial statements.

4

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and six months ended June 30, 2009 and 2010

(Unaudited)

NOTE A – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying consolidated financial statements and notes thereto of GMX Resources Inc. (the “Company” or “GMXR”) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted. The accompanying consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes thereto included in GMXR’s 2009 Annual Report on Form 10-K (“2009 10-K”).

In the opinion of GMXR’s management, all adjustments (all of which are normal and recurring) have been made which are necessary to fairly state the consolidated balance sheet of GMXR as of June 30, 2010, and the results of its operations for the three and six months ended June 30, 2010 and 2009 and its cash flow for the six months ended June 30, 2010 and 2009.

Earnings Per Share

Basic earnings (loss) per common share is computed by dividing the net income (loss) applicable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings (loss) per common share is calculated in the same manner, but also considers the impact to net income (loss) and common shares for the potential dilution from our convertible notes, outstanding stock options and non-vested restricted stock awards. Due to depressed share prices, there were no dilutive shares from the 5.00% convertible notes, outstanding stock options or non-vested restricted stock awards at June 30, 2009 or 2010. Additionally, using the if-converted method, no dilutive shares from the 4.50% convertible notes were included in the computation of diluted earnings per share for the three and six months ended June 30, 2010.

Oil and Natural Gas Properties

The Company follows the full cost method of accounting for its oil and natural gas properties and activities. Accordingly, the Company capitalizes all costs incurred in connection with the acquisition, exploration and development of oil and natural gas properties. The Company capitalizes internal costs that can be directly identified with exploration and development activities, but does not include any costs related to production, general corporate overhead, or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and gas wells, including salaries and benefits and other internal costs directly attributable to these activities. Also included in oil and natural gas properties are tubular and other lease and well equipment of $32.2 million and $13.4 million at December 31, 2009 and June 30, 2010, respectively, that have not been placed in service but for which we plan to utilize in our on-going exploration and development activities.

Capitalized costs are subject to a “ceiling test,” which limits the net book value of oil and natural gas properties less related deferred income taxes to the estimated after-tax future net revenues discounted at a 10-percent interest rate. The lower of cost or fair value of unproved properties is added to the future net revenues less income tax effects. Future net revenues are calculated using prices that represent the average of the first day of the month price for the 12-month period prior to the end of the period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. Based on average natural gas prices for the 12-month period ended December 31, 2009, these cash flow hedges increased the full-cost ceiling by $69.7 million, thereby reducing the ceiling test write-down by the same amount. Excluding the effects of hedges, which increased the full cost ceiling by $63.3 million at June 30, 2010, we would have incurred a ceiling test writedown of $61.2 million for the six months ended June 30, 2010. Our natural gas hedging activities are discussed in Note D of these consolidated financial statements.

Two primary factors impacting the ceiling test are reserve levels and natural gas and oil prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense.

5

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and six months ended June 30, 2009 and 2010

(Unaudited)

Recent Accounting Standards

In October 2009, the FASB issued ASU 2009-15, “Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing,” now codified under FASB ASC Topic 470 “Debt”, (“ASU 2009-15”), which provided guidance for accounting and reporting for own-share lending arrangements issued in contemplation of a convertible debt issuance. At the date of issuance, a share-lending arrangement entered into on an entity’s own shares should be measured at fair value in accordance with Topic 820 and recognized as an issuance cost, with an offset to additional paid-in capital. Loaned shares are excluded from basic and diluted earnings per share unless default of the share-lending arrangement occurs. The amendments also require several disclosures including a description of the terms of the arrangement and the reason for entering into the arrangement. The effective dates of the amendments are dependent upon the date the share-lending arrangement was entered into and include retrospective application for arrangements outstanding as of the beginning of fiscal years beginning on or after December 15, 2009. See Note B.

A standard to improve disclosures about fair value measurements was issued in January 2010. The standard requires additional disclosures about fair value measurements, adding a new requirement to disclose transfers in and out of Levels 1 and 2 measurements and gross presentation of activity within a Level 3 roll forward. The guidance also clarified existing disclosure requirements regarding the level of disaggregation of fair value measurements and disclosures regarding inputs and valuation techniques. We adopted this guidance effective as of the first quarter of 2010. The adoption had no impact on our financial position or results of operations.

NOTE B – SHARE LENDING ARRANGEMENTS AND ADOPTION OF ASU 2009-15.

In February 2008, in connection with the offer and sale of the 5.00% convertible notes, we entered into a share lending agreement (the “Share Lending Agreement”) with an affiliate of Jefferies & Company, Inc. (the “share borrower”) and Jefferies & Company, Inc., as collateral agent for GMXR. Under this agreement, we may loan to the share borrower up to the maximum number of shares of our common stock underlying the 5.00% convertible notes during a specified loan availability period. This maximum number of shares was initially 3,846,150 shares. We will receive a loan fee of $0.001 per share for each share of our common stock that we loan to the share borrower, payable at the time such shares are borrowed. The share borrower may borrow and re-borrow up to the maximum number of shares of our common stock during the loan availability period.

The share borrower’s obligations under the Share Lending Agreement are unconditionally guaranteed by Jefferies Group, Inc., the ultimate parent company of the share borrower and Jefferies & Company, Inc. (the “guarantor”). If the guarantor receives a rating downgrade for its long term unsecured and unsubordinated debt below a specified level by both Standard & Poor’s Ratings Services and Moody’s Investors Service, Inc. (or any substitute rating agency mutually agreed upon by the Company and the share borrower), or by either of such rating agencies in certain circumstances, the share borrower has agreed to post and maintain with Jefferies & Company, Inc., acting as collateral agent for the Company, collateral in the form of cash, government securities, certificates of deposit, high-grade commercial paper of U.S. issuers, letters of credit or money market shares with a market value at least equal to 100% of the market value of the shares of our common stock borrowed by the share borrower as security for the share borrower’s obligation to return the borrowed shares to the Company pursuant to the Share Lending Agreement.

The loan availability period under the Share Lending Agreement commenced on the date of the Share Lending Agreement and will continue until the date that any of the following occurs:

• GMXR notifies the share borrower in writing of our intention to terminate the Share Lending Agreement at any time after the entire principal amount of the 5.00% convertible notes ceases to be outstanding as a result of conversion, repurchase, at maturity or otherwise;

• GMXR and the share borrower agree to terminate the Share Lending Agreement;

• GMXR elects to terminate all of the outstanding loans upon a default by the share borrower under the Share Lending Agreement or by the guarantor under its guarantee, including a breach by the share borrower of any of its obligations or a breach in any material respect of any of the representations or covenants under the Share Lending Agreement or a breach by the guarantor of the guarantee, or the bankruptcy of the share borrower or the guarantor; or

• the share borrower elects to terminate all outstanding loans upon the bankruptcy of the Company.

Any shares GMXR loans to the share borrower will be issued and outstanding for corporate law purposes, however, the borrowed shares will not be considered outstanding for the purpose of computing and reporting earnings per share. The holders of the borrowed shares will have all of the rights of a holder of a share of our outstanding common stock, including the right to vote the shares on all matters submitted to a vote of the Company’s shareholders and the right to receive any dividends or other distributions that we may pay or make on our outstanding shares of common stock. However, under the Share Lending Agreement, the share borrower has agreed:

• not to vote any shares of the Company’s common stock it has borrowed to the extent it owns such borrowed shares; and

• to pay to GMXR an amount equal to any cash dividends that GMXR pays on the borrowed shares.

6

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and six months ended June 30, 2009 and 2010

(Unaudited)

On January 1, 2010, the Company was required to adopt ASU 2009-15, which changes the accounting treatment of the Company’s share lending arrangements. Under ASU 2009-15, the Company must recognize the value of share lending arrangements as issuance cost at inception.

The comparative financial statements have been restated to apply the new pronouncement retrospectively. The following financial statement line items in the consolidated balance sheet as of December 31, 2009 were affected by the adoption:

	As Reported			Adjustments		As Adjusted
	(in thousands)
ASSETS
CURRENT ASSETS:
Prepaid expenses and deposits	$	3,809		$	697	$	4,506
OTHER ASSETS	$	6,748		$	1,736	$	8,484
LIABILITIES AND EQUITY
EQUITY
Additional paid-in capital	$	520,307		$	2,338	$	522,645
Accumulated deficit	$	(284,840	)	$	95	$	(284,745	)

The following financial statement line items in the consolidated statement of operations for the three and six months ended June 30, 2009 were affected by the adoption:

	Three Months ended June 30, 2009
	As Reported			Adjustments			As Adjusted
	(in thousands)
NON-OPERATING INCOME (EXPENSES)
Interest expense	$	(3,942	)	$	(153	)	$	(4,095	)
NET LOSS	$	(63	)	$	(153	)	$	(216	)
NET LOSS APPLICABLE TO COMMON SHAREHOLDERS	$	(1,220	)	$	(153	)	$	(1,373	)
EARNINGS (LOSS) PER SHARE – BASIC	$	(0.07	)	$	(0.01	)	$	(0.08	)
EARNINGS (LOSS) PER SHARE – DILUTED	$	(0.07	)	$	(0.01	)	$	(0.08	)
	Six Months ended June 30, 2009
	As Reported			Adjustments			As Adjusted
	(in thousands)
NON-OPERATING INCOME (EXPENSES)
Interest expense	$	(7,850	)	$	(301	)	$	(8,151	)
NET LOSS	$	(131,917	)	$	(301	)	$	(132,218	)
NET LOSS APPLICABLE TO COMMON SHAREHOLDERS	$	(134,230	)	$	(301	)	$	(134,531	)
EARNINGS (LOSS) PER SHARE – BASIC	$	(8.02	)	$	(.01	)	$	(8.03	)
EARNINGS (LOSS) PER SHARE – DILUTED	$	(8.02	)	$	(.01	)	$	(8.03	)

As of June 30, 2010, 2,640,000 shares of our common stock were subject to outstanding loans to the share borrower with a fair value of $17.1 million. The unamortized amount of issuance costs associated with the share lending agreement is $2.1 million at June 30, 2010, of which $0.7 million is classified as a current asset and $1.4 million is a long-term asset included in Other Assets. The Company recognized $0.3 million in interest expense relating to the amortization of the Share Lending Agreement for the six months ended June 30, 2010.

7

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and six months ended June 30, 2009 and 2010

(Unaudited)

NOTE C – LONG-TERM DEBT

The table below presents the carrying amounts and approximate fair values of our debt obligations. The carrying amounts of our revolving bank credit facility borrowings approximate their fair values due to the short-term nature and frequent repricing of these obligations. The approximate fair values of our convertible debt securities are determined based on market quotes from independent third party brokers as they are actively traded in an established market.

	December 31, 2009				June 30, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in thousands)
Revolving bank credit facility(1)	$	—	$	—	$	26,000	$	26,000
5.00% Convertible Senior Notes due February 2013		115,646		111,406		117,043		91,250
4.50% Convertible Senior Notes due May 2015		73,187		87,652		74,192		58,596
Joint venture financing(2)		1,445		1,445		1,395		1,395
Total	$	190,278	$	200,503	$	218,630	$	177,241

⁽¹⁾ Maturity date of August 2012 but can be extended until July 2013 under certain circumstances; this facility is collateralized by all assets of the Company

⁽²⁾ Non-recourse, no interest rate

Revolving Bank Credit Facility

Our revolving bank credit facility contains various affirmative and restrictive covenants. These covenants, among other things, prohibit additional indebtedness, sales of assets, mergers and consolidations, dividends and distributions, and changes in management and require the maintenance of various financial ratios. The required and actual financials ratios as of June 30, 2010 are shown below:

Financial Covenant	Required Ratio	Actual Ratio
Current ratio (1)	Not less than 1 to 1	2.59 to 1
Ratio of total net debt to EBITDA (as defined in the revolving bank credit facility)(2)	Not greater than 4.5 to 1	3.60 to 1
Ratio of EBITDA, as defined in the revolving bank credit facility agreement to cash interest expense(3)	Not less than 3 to 1	3.38 to 1

⁽¹⁾ Current ratio is defined in our revolving bank credit facility as the ratio of current assets plus the unused and available portion of the revolving bank credit facility ($104 million as of June 30, 2010) to current liabilities. The calculation will not include the effects, if any, of derivatives under ASC 815. As of June 30, 2010, current assets included derivatives assets of $16.3 million. In addition, the 5.00% convertible notes and the 4.50% convertible notes are not considered a current liability unless one or more of such convertible notes have been surrendered for conversion and then only to the extent of the cash payment due on the conversion of the notes surrendered. As of June 30, 2010, none of the 5.00% convertible notes and the 4.50% convertible notes had been surrendered for conversion.

⁽²⁾ EBITDA as defined in our revolving bank credit facility for the twelve months ended June 30, 2010 is calculated as follows (amounts in thousands):

Net loss	$	(44,789	)
Plus:
Interest expense		17,480
Early extinguishment of debt		4,976
Impairment of oil and natural gas properties		50,072
Depreciation, depletion and amortization		30,606
Non-cash compensation and other expenses		6,868
Less:
Income tax benefit		(3,978	)
EBITDA	$	61,235

⁽³⁾ Cash interest expense is defined in the revolving bank credit facility as all interest, fees, charges, and related expenses payable in cash for the applicable period payable to a lender in connection with borrowed money or the deferred purchase price of assets that is considered interest expense under GAAP, plus the portion of rent paid or payable for that period under capital lease

8

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and six months ended June 30, 2009 and 2010

(Unaudited)

obligations that should be treated as interest. For the twelve months ended June 30, 2010, cash interest expense included fees paid related to bank financing activities and other loan fees of $1.5 million. As of June 30, 2010, non-cash interest expense of $6.2 million was deducted from interest expense to arrive at the cash interest expense used in the debt covenant calculation. Non-cash interest expense primarily relates to the amortization of debt issuance costs and convertible debt discount. Capitalized interest of $2.2 million was added to interest expense.

As of June 30, 2010, the Company was in compliance with all financial covenants under the revolving bank credit facility.

The revolving bank credit facility provides for a line of credit up to $250 million, subject to a borrowing base which is based on a periodic evaluation of oil and gas reserves. As of June 30, 2010, we had $26 million drawn on our revolving bank credit facility that has a borrowing base of $130 million. In July 2010, the maturity date for amounts borrowed by the Company pursuant to the revolving bank credit facility was extended from July 15, 2011, to August 1, 2012. In addition, the Company may automatically extend this maturity date to July 8, 2013, if, on or prior to July 31, 2012, all of the Company’s $125 million aggregate principal amount of 5.00% convertible senior notes due 2013 (the “5.00% convertible notes”) either have been fully converted to common stock of the Company or have been paid in full with the proceeds of an equity offering or new debt with a maturity date no earlier than 180 days after July 8, 2013, and issued in compliance with the revolving bank credit facility. In addition, the financial covenant of the Company relating to the maximum ratio of total net debt to EBITDA (as defined in the revolving bank credit facility) was amended. First, the definition of “total net debt” was modified to include only the portions of the 5.00% convertible notes and the Company’s $86.25 million aggregate principal amount of 4.50% convertible senior notes (the “4.50% convertible notes) classified as indebtedness and to exclude the portions of the 5.00% convertible notes and the 4.50% convertible notes classified as equity under generally accepted accounting principles. Additionally, the maximum permitted ratio of total net debt to EBITDA was increased from 4.00 to 1.00 to 4.50 to 1.00 for the period of June through December 2010 and to 4.25 to 1.00 for the period from January 2011 through June 2011. Commencing in July 2011, the maximum permitted ratio of total net debt to EBITDA will again be 4.00 to 1.00.

5.00% Convertible Senior Notes

As of June 30, 2010, the net carrying amount of the 5.00% convertible notes was as follows (amounts in thousands):

Principal amount	$	125,000
Less: Unamortized debt discount		7,957
Carrying amount	$	117,043

The 5.00% convertible notes bear interest at a rate of 5.00% per year, payable semiannually in arrears on February 1 and August 1 of each year, beginning August 1, 2008. As a result of the amortization of the debt discount through non-cash interest expense, the effective interest rate on the 5.00% convertible notes is 8.7% per annum. For the three and six months ended June 30, 2009 and 2010, interest costs on the convertible notes included $1.6 million and $3.1 million, respectively, relating to the contractual interest coupon. For the three and six months ended June 30, 2009, interest costs were $1.0 million and $1.8 million, respectively related to the amortization of the debt discount and for the three and six months ended June 30, 2010, these interest costs were $0.9 million and $1.8 million, respectively

As of June 30, 2010, the unamortized discount is expected to be amortized into earnings over 2.6 years. The carrying value of the equity component of the 5.00% convertible notes was $9.3 million as of June 30, 2010.

4.50% Convertible Senior Notes

As of June 30, 2010, the net carrying amount of the 4.50% convertible notes was as follows (amounts in thousands):

Principal amount	$	86,250
Less: Unamortized debt discount		12,058
Carrying amount	$	74,192

The 4.50% convertible notes bear interest at a rate of 4.50% per year, payable semiannually in arrears on November 1 and May 1 of each year, beginning May 1, 2010. As a result of the amortization of the debt discount through non-cash interest expense, the effective interest rate on the 4.50% convertible notes is 9.09% per annum. The amount of the cash interest expense recognized with respect to the 4.50% contractual interest coupon for the three and six months ended June 30, 2010 was $1.1 million and $1.9 million, respectively. The amount of non-cash interest expense for the three and six months ended June 30, 2010 related to the amortization of the debt discount and transaction costs was $0.6 million and $1.2 million, respectively. The 4.50% convertible notes had not yet been issued at June 30, 2009. As of June 30, 2010, the unamortized discount is expected to be amortized into earnings over 4.8 years. The carrying value of the equity component of the 4.50% convertible notes was $8.4 million as of June 30, 2010.

9

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and six months ended June 30, 2009 and 2010

(Unaudited)

NOTE D – DERIVATIVE ACTIVITIES

The following is a summary of the asset and liability fair values of our derivative contracts:

		Asset Fair Value
	Balance Sheet Location	December 31, 2009		June 30, 2010
		(in thousands)
Derivatives designated as Hedging Instruments under ASC 815
Natural gas	Current derivative asset	$	12,896	$	19,791
Natural gas	Derivative asset – non-current		19,144		24,140
Total derivative asset fair value		$	32,040	$	43,931
		Liability Fair Value
	Balance Sheet Location	December 31, 2009		June 30, 2010
		(in thousands)
Derivatives designated as Hedging Instruments under ASC 815
Natural gas	Current derivative asset	$	—	$	2,889
Natural gas basis	Current derivative asset		—		455
Natural gas	Derivative assets – non-current		549		3,821
Natural gas basis	Derivative assets – non-current		—		540
		$	549	$	7,705
Derivatives not designated as Hedging Instruments under ASC 815
Natural gas	Current derivative asset	$	374	$	—
Natural gas basis	Current derivative asset		270		—
Natural gas	Derivative assets – non-current		1,303		—
Crude oil	Current derivative assets		—		67
Crude oil	Derivative assets – non-current		—		96
		$	1,947	$	163
Total derivative liability fair value		$	2,496	$	7,868
Net derivative fair value		$	29,544	$	36,063

10

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and six months ended June 30, 2009 and 2010

(Unaudited)

Following is a summary of the outstanding volumes and prices on our derivative contracts in place as of June 30, 2010:

Effective Date	Maturity Date	Notional Amount Per Month	Remaining Notional Amount as of June 30, 2010	Additional Put Options		Floor		Ceiling		Designation under ASC 815
Natural Gas (MMBtu):
1/1/2010	12/31/2010	452,667	2,716,000	$	5.00	$	7.50	$	—	Cash flow hedge
1/1/2010	12/31/2010	471,833	2,830,998	$	4.00	$	5.50	$	7.00	Cash flow hedge
1/1/2010	12/31/2010	25,000	150,000			$	—	$	8.50	Cash flow hedge
5/1/2010	12/31/2012	155,550	4,666,500			$	—	$	7.00	Cash flow hedge
5/1/2010	12/31/2010	271,667	1,630,000	$	4.00	$	6.00	$	—	Cash flow hedge
1/1/2011	12/31/2011	188,781	2,265,372			$	—	$	8.00	Cash flow hedge
1/1/2011	3/31/2011	200,000	600,000	$	5.00	$	7.00	$	7.25	Cash flow hedge
1/1/2011	3/31/2011	200,000	600,000			$	—	$	8.90	Cash flow hedge
4/1/2011	10/31/2011	200,000	1,400,000	$	5.00	$	6.50	$	8.30	Cash flow hedge
11/1/2011	3/31/2012	200,000	1,000,000	$	5.50	$	7.00	$	10.10	Cash flow hedge
1/1/2011	12/31/2012	1,021,666	24,520,000	$	4.00	$	6.00	$	—	Cash flow hedge
1/1/2011	12/31/2012	167,612	4,022,697	$	4.50	$	6.25	$	—	Cash flow hedge
Crude Oil (Bbls):
5/1/2010	12/31/2011	3,000	54,900			$	—	$	100.00	Not designated

Natural gas contracts are settled against Inside FERC—Houston Ship Channel Index Price or NYMEX. The Inside FERC—Houston Ship Channel Index Price and NYMEX have historically had a high degree of correlation with the actual prices received by the Company.

Effects of derivative instruments on the Condensed Consolidated Statement of Operations

For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.

11

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and six months ended June 30, 2009 and 2010

(Unaudited)

A summary of the effect of the derivatives qualifying for hedges is as follows:

	For the Three Months Ended June 30, 2009
	Amount of Gain (Loss)  Recognized in OCI on Derivative (Effective Portion)			Location of Gain Reclassified from Accumulated OCI into Income (Effective Portion) and Location of Gain Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Amount of  Gain Reclassified from Accumulated  OCI into Income (Effective Portion)		Amount of Gain Recognized  in Income on Derivative (Ineffective  Portion and Amount Excluded from Effectiveness Testing)
	(in thousands)				(in thousands)
Natural gas	$	(1,082	)	Oil and Gas Sales	$	6,960	$	188
Crude oil		67		Oil and Gas Sales		714		—
	$	(1,015	)		$	7,674	$	188
	For the Six Months Ended June 30, 2009
	Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			Location of Gain Reclassified from Accumulated OCI into Income (Effective Portion) and Location of Gain Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Amount of Gain Reclassified from Accumulated OCI into Income (Effective Portion)		Amount of Gain Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
	(in thousands)				(in thousands)
Natural gas	$	16,421		Oil and Gas Sales	$	14,640	$	992
Crude oil		57		Oil and Gas Sales		1,448		—
	$	16,478			$	16,088	$	992
	For the Three Months Ended June 30, 2010
	Amount of Gain (Loss)  Recognized in OCI on Derivative (Effective Portion)			Location of Gain Reclassified from Accumulated OCI into Income (Effective Portion) and Location of Gain Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Amount of  Gain Reclassified from Accumulated  OCI into Income (Effective Portion)		Amount of Gain Recognized  in Income on Derivative (Ineffective  Portion and Amount Excluded from Effectiveness Testing)
	(in thousands)				(in thousands)
Natural gas	$	359		Oil and Gas Sales	$	7,325	$	(1,786	)
	For the Six Months Ended June 30, 2010
	Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			Location of Gain Reclassified from Accumulated OCI into Income (Effective Portion) and Location of Gain Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Amount of Gain Reclassified from Accumulated OCI into Income (Effective Portion)		Amount of Gain Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
	(in thousands)				(in thousands)
Natural gas	$	18,567		Oil and Gas Sales	$	10,964	$	(1,257	)

Assuming that the market prices of oil and gas futures as of June 30, 2010 remain unchanged, the Company would expect to transfer a gain of approximately $16 million from accumulated other comprehensive income to earnings during the next 12 months. The actual reclassification into earnings will be based on market prices at the contract settlement date.

12

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and six months ended June 30, 2009 and 2010

(Unaudited)

For derivative instruments that do not qualify as hedges pursuant to ASC 815, changes in the fair value of these derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are recognized in current earnings. A summary of the effect of the derivatives not qualifying for hedges is as follows:

	Three Months Ended June 30, 2009				Six Months Ended June 30, 2009
	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative			Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
		(in thousands)				(in thousands)
Realized
Natural gas	Oil and gas sales	$	2,023		Oil and gas sales	$	2,739
Unrealized
Natural gas	Unrealized losses on derivatives		(1,114	)	Unrealized losses on derivatives		(1,314	)
Natural gas basis	Unrealized losses on derivatives		86		Unrealized losses on derivatives		(57	)
		$	995			$	1,368
	Three Months Ended June 30, 2010				Six Months Ended June 30, 2010
	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative			Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
		(in thousands)				(in thousands)
Realized
Natural gas	Oil and gas sales	$	—		Oil and gas sales	$	23
Unrealized
Natural gas	Unrealized losses on derivatives		—		Unrealized losses on derivatives		(221	)
Crude oil	Unrealized losses on derivatives		107		Unrealized losses on derivatives		107
		$	107			$	(91	)

The valuation of our derivative instruments are based on industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instrument. The Company categorizes these measurements as Level 2. The following table sets forth by level within the fair value hierarchy our derivative instruments, which are our only financial assets and liabilities that were accounted for at fair value on a recurring basis, as of December 31, 2009 and June 30, 2010:

	As of December 31, 2009:						As of June 30, 2010:
	Quoted Prices  in Active Markets (Level  1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Quoted Prices in Active Markets (Level  1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(in thousands)
Financial assets:
Natural gas derivative instruments	$	—	$	29,544	$	—	$	—	$	36,227		$	—
Crude oil derivative instruments	$	—	$	—	$	—	$	—	$	(164	)	$	—

NOTE E – STOCK COMPENSATION PLANS

We recognized $1.2 million and $1.1 million of stock compensation expense for the three months ending June 30, 2009 and 2010, respectively and $2.3 million and $3.5 million for the six months ending June 30, 2009 and 2010, respectively. These non-cash expenses are reflected as a component of the Company’s general and administrative expense. To the extent amortization of

13

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and six months ended June 30, 2009 and 2010

(Unaudited)

compensation costs relates to employees directly involved in exploration and development activities, such amounts are capitalized to oil and natural gas properties. Stock based compensation capitalized as part of oil & natural gas properties was $0.2 million and $0.1 million for the three months ended June 30, 2009 and 2010 and $0.4 million and $0.7 million for the six months ended June 30, 2009 and 2010.

Restricted Stock

A summary of the status of our unvested shares of restricted stock and the changes for the years ending December 31, 2008 and 2009 and the six months ended June 30, 2010 is presented below:

	Number  of unvested restricted shares		Weighted average  grant- date fair value per share
Unvested shares as of January 1, 2008	—		$	—
Granted	79,347		$	74.11
Vested	(16,521	)	$	76.65
Forfeited	(98	)	$	76.73
Unvested shares as of December 31, 2008	62,728		$	73.44
Granted	542,847		$	18.55
Vested	(23,574	)	$	70.38
Forfeited	(1,471	)	$	29.00
Unvested shares as of December 31, 2009	580,530		$	22.35
Granted	14,387		$	8.67
Vested	(217,813	)	$	25.43
Forfeited	(18,115	)	$	23.73
Unvested shares as of June 30, 2010	358,989		$	19.86

As of June 30, 2010, there was $7.0 million of unrecognized compensation expense related to non-vested restricted stock grants. This unrecognized compensation cost is expected to be recognized over a weighted-average period of 2.4 years.

NOTE F – CAPITAL STOCK

Share Lending Arrangement

During the six months ended June 30, 2010, 500,000 shares issued and outstanding under the Company’s Share Lending Agreement were returned.

NOTE G – INCOME TAXES

We recorded tax provisions (benefits) of $3.0 million and $2.4 million for the three months ended June 30, 2009 and 2010, respectively, and $0.5 million and $(3.4) million for the six months ended June 30, 2009 and 2010, respectively, due to changes in the valuation allowance on deferred tax assets. The valuation allowance was adjusted due to increases or decreases in offsetting deferred tax liabilities, primarily as a result of unrealized gains or losses on derivative instruments that qualify for hedge accounting. In determining the carrying value of a deferred tax asset, accounting standards provide for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. As the Company has incurred net operating losses in prior years, relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are insufficient to overcome a history of such losses. In 2008, the Company reduced the carrying value of its net deferred tax asset to zero and maintained that position as of December 31, 2009 and June 30, 2010. The valuation allowance has no impact on our net operating loss (“NOL”) position for tax purposes, and if the Company generates taxable income in future periods, the Company will be able to use its NOLs to offset taxes due at that time. The Company will continue to assess the valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.

NOTE H – COMMITMENTS AND CONTINGENCIES

As disclosed in the 2009 10-K, the Company has lease obligations related to four drilling rigs. During 2010, the Company subleased two of these drilling rigs for approximately six months. As a result of these subleases, the Company has reduced its future lease obligation by approximately $7.6 million.

14

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and six months ended June 30, 2009 and 2010

(Unaudited)

The Company is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to the Company and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, the Company’s estimates of the outcomes of such matters, and its experience in contesting, litigating, and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to the Company’s financial position or results of operations after consideration of recorded accruals.

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operation.

General

We are an independent oil and gas company engaged in the exploration, development and production of oil and natural gas from the Haynesville/Bossier Shale and Cotton Valley Sands in our core area, the Sabine Uplift of the Carthage, North Field of Harrison and Panola counties of east Texas. We consider and report all of our operations as one segment because our operating areas have similar economic characteristics and each meet the criteria for aggregation as defined in the Financial Accounting Standards Board Accounting Standards Codification 280.

Our strategy is to grow shareholder value through Haynesville/Bossier Shale horizontal well development as well as Cotton Valley Sand wells, to continue acreage acquisitions in our core area, to focus on operational growth in and around our core area, and to convert our natural gas reserves to proved reserves, while maintaining balanced prudent financial management.

The table below summarizes information concerning our activities in the three and six months ended June 30, 2010 compared to the three and six months ended June 30, 2009.

Summary Operating Data

	Three Months Ended June  30,				Six Months Ended June  30,
	2009		2010		2009			2010
Production:
Oil (MBbls)		33		24		63			46
Natural gas (MMcf)		3,113		4,164		6,155			7,231
Gas equivalent production (MMcfe)		3,309		4,308		6,533			7,507
Average daily (MMcfe)		36.4		47.3		36.1			41.5
Average Sales Price:
Oil (per Bbl)
Wellhead price	$	54.04	$	75.98	$	45.50		$	75.73
Effect of hedges, excluding gain or loss from ineffectiveness of derivatives		21.84		—		22.99			—
Total	$	75.88	$	75.98	$	68.49		$	75.73
Natural gas (per Mcf)
Wellhead price	$	3.36	$	3.81	$	3.73		$	4.33
Effect of hedges, excluding gain or loss from ineffectiveness of derivatives		3.12		1.76		2.82			1.51
Total	$	6.48	$	5.57	$	6.55		$	5.84
Average sales price, excluding gain or loss from ineffectiveness of derivatives (per Mcfe)	$	6.84	$	5.80	$	6.84		$	6.10
Operating and Overhead Costs (per Mcfe):
Lease operating expenses	$	0.82	$	0.52	$	0.90		$	0.71
Production and severance taxes		0.09		0.07		(0.21	)		0.14
General and administrative		1.61		1.44		1.50			1.79
Depreciation, depletion and amortization—oil and natural gas properties	$	1.41	$	1.75	$	1.79		$	1.70

15

Results of Operations for the Three Months Ended June 30, 2010 Compared to the Three Months Ended June 30, 2009

Oil and Natural Gas Sales. Oil and natural gas sales in the three months ended June 30, 2010 increased 2% to $23.2 million compared to $22.8 million for the three months ended June 30, 2009. Excluding the non-cash effects of ineffectiveness from derivatives, oil and gas sales increased 10% from the second quarter of 2009 compared to the second quarter of 2010. Ineffectiveness of derivatives recognized in oil and gas sales of $0.2 million and $(1.8) million for the three months ended June 30, 2009 and 2010, respectively, is the result of a difference in the fair value of the Company’s cash flow hedges and the fair value of the projected cash flows of a hypothetical derivative based on the Company’s expected sales point. The increase in oil and natural gas sales was due to a 30% increase in production offset by a 15% decrease in the average realized price of oil and natural gas, excluding ineffectiveness of hedging activities. The average price per barrel of oil and Mcf of natural gas received (exclusive of ineffectiveness from derivatives) in the three months ended June 30, 2010 was $75.98 and $5.57, respectively, compared to $75.88 and $6.48, respectively, in the three months ended June 30, 2009. Production of oil for the three months ended June 30, 2010 decreased to 24 MBbls compared to 33 MBbls for the three months ended June 30, 2009, a decrease of 27%. Natural gas production for the three months ended June 30, 2010 increased to 4,164 MMcf compared to 3,113 MMcf for the three months ended June 30, 2009, an increase of 34%. The increase in natural gas production resulted from production related to 19 producing Haynesville/Bossier (“H/B”) horizontal wells that were on-line during 2010. During the second quarter of 2010, the Company brought on-line six H/B horizontal wells and production from H/B horizontal wells accounted for 61% of total production in the second quarter of 2010 compared to 31% in the second quarter of 2009.

In the three months ended June 30, 2010, as a result of hedging activities but excluding derivative ineffectiveness, we recognized an increase in natural gas sales of $7.3 million compared to an increase in natural gas and oil sales of $9.7 million and $0.7 million, respectively, in the second quarter of 2009. In the second quarter of 2010, hedging, excluding ineffectiveness, increased the average natural gas sales price by $1.76 per Mcf compared to an increase in natural gas and oil sales price of $3.12 per Mcf and $21.84 per Bbl, respectively, in the second quarter of 2009. The Company did not recognize any oil related hedging activities in oil and gas sales in the three months ended June 30, 2010.

Lease Operations. Lease operations expense decreased $0.5 million, or 18%, in the three months ended June 30, 2010 to $2.2 million, compared to$2.7 million for the three months ended June 30, 2009. Lease operations expense on an equivalent unit of production basis decreased $0.30 per Mcfe in the three months ended June 30, 2010 to $0.52 per Mcfe, compared to $0.82 per Mcfe for the three months ended June 30, 2009. The decrease in lease operating expenses on an equivalent unit basis resulted from an increase in H/B horizontal well production and cost control measures implemented during 2010. With little to no incremental increase in lease operating costs from a Cotton Valley vertical well, the significantly larger amount of production from a H/B horizontal well will result in lower per unit lease operating costs.

Production and Severance Taxes.Production and severance taxes increased 3% to $0.3 million in the three months ended June 30, 2010. During the second quarter of 2010, the Company recorded production and severance tax refunds of $0.5 million. Upon approval by the State of Texas, certain wells, including our H/B horizontal wells, are exempt from severance taxes for a period of ten years. We expect this to continue to reduce our expense going forward.

Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense increased $2.1 million, or 31%, to $8.7 million in the three months ended June 30, 2010 compared to $6.6 million for the three months ended June 30, 2009. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.75 per Mcfe in the three months ended June 30, 2010 compared to $1.41 per Mcfe in the three months ended June 30, 2009. This increase is a result of our H/B horizontal drilling program which caused the percentage increase in oil and gas properties subject to amortization to exceed the percentage growth in reserves for the three months ended June 30, 2010.

General and Administrative Expense.General and administrative expense for the second quarter of 2010 was $6.2 million compared to $5.3 million for the second quarter of 2009, an increase of 17%. General and administrative expense per equivalent unit of production was $1.44 per Mcfe for the second quarter of 2010 compared to $1.61 per Mcfe for the comparable period in 2009. A significant portion of the Company’s general and administrative expense is related to non-cash compensation expense. During the three months ended June 30, 2009 and 2010, the Company recognized $1.2 million and $0.9 million of non-cash compensation expense. General and administrative expense has not historically varied in direct proportion to oil and natural gas production because certain types of general and administrative expenses are non-recurring or fixed in nature. The Company expects general and administrative expenses on a per Mcfe basis to decrease as production increases.

Interest.Interest expense for the second quarter of 2010 was $4.7 million compared to $4.1 million for the first quarter of 2009. For the three months ended June 30, 2010 and 2009, interest expense includes non-cash interest expense of $2.3 million and $1.2 million, respectively. As a result of the accounting for convertible bonds, share lending agreement and deferred premiums on derivative instruments, the Company’s non-cash interest expense related to these financial instruments was $1.7 million and $0.8 million for the three months ended June 30, 2010 and 2009, respectively. Cash interest expense for the three months ended June 30, 2010 and 2009 was $2.3 million and $2.9 million, respectively. The decrease in cash interest expense of $0.6 million is due to the reduction in borrowing under the revolving credit agreement in the second quarter of 2010 compared to the second quarter of 2009.

16

Income Taxes. Income tax for the second quarter of 2010 was a provision of $2.4 million as compared to a provision of $3.0 million in the second quarter of 2009. The income tax provision recognized in the second quarters of 2009 and 2010 was a result of an increase in the valuation allowance on net deferred tax assets. A decrease in deferred tax liabilities primarily related to unrealized gains on derivative contracts designated as hedges where the mark to market change on the hedges, net of deferred taxes is recorded to other comprehensive income.

Net income to noncontrolling interest. As the result of a sale of an interest in our gathering system in the fourth quarter of 2009, we reduced net income by $0.6 million or $0.14 per Mcfe in the three months ended June 30, 2010.

Results of Operations for the Six Months Ended June 30, 2010 Compared to the Six Months Ended June 30, 2009

Oil and Natural Gas Sales. Oil and natural gas sales in the six months ended June 30, 2010 decreased 3% to $44.5 million compared to $45.7 million for the six months ended June 30, 2009. Excluding the non-cash effects of ineffectiveness from derivatives, oil and gas sales increased 2% from the first six months of 2009 compared to the first six months of 2010. Ineffectiveness of derivatives recognized in oil and gas sales of $1.0 million and $(1.3) million for the six months ended June 30, 2009 and 2010, respectively, is the result of a difference in the fair value of the Company’s cash flow hedges and the fair value of the projected cash flows of a hypothetical derivative based on the Company’s expected sales point. The increase in sales, excluding ineffectiveness of derivatives, was due to a 15% increase in production offset by an 11% decrease in the average realized price of oil and natural gas. The average price per barrel of oil and Mcf of natural gas received (exclusive of ineffectiveness from derivatives) for the six months ended June 30, 2010 was $75.73 and $5.84, respectively, compared to $68.49 and $6.55, respectively, for the six months ended June 30, 2009. Production of oil for the six months ended June 30, 2010 decreased to 46 MBbls compared to 63 MBbls for the six months ended June 30, 2009, a decrease of 27%. Natural gas production for the six months ended June 30, 2010 increased to 7,231 MMcf compared to 6,155 MMcf for the six months ended June 30, 2009, an increase of 17%. The increase in natural gas production resulted from production related to 19 producing Haynesville/Bossier (“H/B”) horizontal wells that were on-line during 2010. During the first half of 2010, the Company brought on-line eight H/B horizontal wells and production from H/B horizontal wells accounted for 55% of total production in the first six months of 2010 compared to 23% in the first six months of 2009.

In the six months ended June 30, 2010, as a result of hedging activities but excluding derivative ineffectiveness, we recognized an increase in natural gas sales of $10.9 million compared to an increase in natural gas and oil sales of $17.4 million and $1.4 million, respectively, in the first six months of 2009. In the first six months of 2010, hedging, excluding ineffectiveness, increased the average natural gas sales price by $1.51 per Mcf compared to an increase in natural gas and oil sales price of $2.82 per Mcf and $22.99 per Bbl, respectively, in the first six months of 2009. The Company did not recognize any oil related hedging activities in oil and gas sales in the first six months of 2010.

Lease Operations. Lease operations expense decreased $0.5 million, or 9%, in the six months ended June 30, 2010 to $5.4 million, compared to $5.9 million in the six months ended June 30, 2009. Lease operations expense on an equivalent unit of production basis decreased $0.19 per Mcfe in the six months ended June 30, 2010 to $0.71 per Mcfe, compared to $0.90 per Mcfe for the six months ended June 30, 2009. The decrease in lease operating expenses on an equivalent unit basis resulted from an increase in H/B horizontal well production and cost control measures implemented during the first six months of 2010. With little to no incremental increase in lease operating costs from a Cotton Valley vertical well, the significantly larger amount of production from a H/B horizontal well will result in lower per unit lease operating costs.

Production and Severance Taxes.As a result of the recognition of severance tax refunds of approximately $2.0 million in the six months ended June 30, 2009, production and severance taxes increased 176% from income of $1.4 million in the six months ended June 30, 2009 to expense of $1.0 million in the six months ended June 30, 2010. During the second quarter of 2010, the Company recorded production and severance tax refunds of $0.5 million. Upon approval by the State of Texas, certain wells, including our H/B horizontal wells, are exempt from severance taxes for a period of ten years and we expect this to reduce our expense going forward.

Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense decreased $0.4 million, or 3%, to $15.1 million in the six months ended June 30, 2010 compared to $15.5 million for the six months ended June 30, 2009. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.70 per Mcfe in the six months ended June 30, 2010 compared to $1.79 per Mcfe in the six months ended June 30, 2009. This decrease in the rate per Mcfe is due to the percentage growth in reserves exceeding the percentage increase in oil and gas properties subject to amortization in the six months ended June 30, 2010 compared to the same period in 2009.

Impairment of Oil and Natural Gas Properties.As a result of lower oil and natural gas prices from year-end 2008, we recognized an impairment charge on oil and gas properties of $138.1 million in the first six months of 2009. The Company has not recognized an impairment charge on oil and gas properties in the first six months of 2010 but may be required to recognize impairment charges or writedowns in future reporting periods if market prices for oil or natural gas decline.

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General and Administrative Expense. General and administrative expense for the six months ended June 30, 2010 was $13.4 million compared to $9.8 million for the six months ended June 30, 2009, an increase of $3.6 million, or 37%. The Company incurred approximately $1.5 million in severance costs of which $0.9 million or 62% was a non-cash expense. Adjusting for the severance costs incurred in the first six months of 2010, general and administrative expense per equivalent unit of production was $1.58 per Mcfe for the first six months of 2010 compared to $1.50 per Mcfe for the comparable period in 2009. A significant portion of the Company’s general and administrative expense is related to non-cash compensation expense. In addition to the $0.9 million in non-cash compensation mentioned above, the Company incurred an additional $2.6 million in non-cash compensation costs during the first six months of 2010 or 22% of general and administrative expenses excluding severance costs in the first six months of 2010 compared to $2.3 million or 23% in the first six months of 2009. General and administrative expense has not historically varied in direct proportion to oil and natural gas production because certain types of general and administrative expenses are non-recurring or fixed in nature. In the second half of 2009, the Company added key employees to execute a H/B horizontal drilling program. As a result, personnel costs have increased in comparison to the first six months of 2009. The Company expects general and administrative expenses on a per Mcfe basis to decrease as production increases.

Interest.Interest expense for the first six months of 2010 was $8.9 million compared to $8.2 million for the first six months of 2009. For the six months ended June 30, 2010 and 2009, interest expense includes non-cash interest expense of $4.5 million and $2.2 million, respectively. As a result of the accounting for convertible bonds, share lending agreement and deferred premiums on derivative instruments, the Company’s non-cash interest expense related to these financial instruments was $3.2 million and $1.6 million for the six months ended June 30, 2010 and 2009, respectively. Cash interest expense for the three months ended June 30, 2010 and 2009 was $4.3 million and $5.7 million, respectively. The decrease in cash interest expense of $1.4 million is due to the reduction in borrowing under the revolving credit agreement in the first six months of 2010 compared to the first six months of 2009.

Income Taxes. Income tax for the six months ended June 30, 2010 was a benefit of $3.4 million as compared to a provision of $0.5 million in the first six months of 2009. The income taxes recognized in the first six months of 2009 and 2010 were a result of a change in the valuation allowance on net deferred tax assets caused by a change in deferred tax liabilities primarily related to unrealized gains on derivative contracts designated as hedges where the mark to market change on the hedges, net of deferred taxes is recorded to other comprehensive income.

Net income to noncontrolling interest. As the result of a sale of an interest in our gathering system in the fourth quarter of 2009, we reduced net income by $0.9 million or $0.12 per Mcfe for the six months ended June 30, 2010.

Net Income and Net Income Per Share

Net Income and Net Income Per Share—Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009.For the three months ended June 30, 2010 we reported a net loss applicable to common shareholders of $3.0 million and for the three months ended June 30, 2009, we reported a net loss applicable to common shareholders of $1.4 million. Net loss per basic and fully diluted share was $0.11 for the second quarter of 2010 compared to a net loss per basic and fully diluted share of $0.08 for the second quarter of 2009. Weighted average fully-diluted shares outstanding increased by 56% from 18,093,208 shares in the second quarter of 2009 to 28,181,587 shares in the second quarter of 2010.

Net Income and Net Income Per Share—Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009.For the six months ended June 30, 2010 we reported a net income applicable to common shareholders of $0.8 million and for the six months ended June 30, 2009, we reported a net loss applicable to common shareholders of $134.5 million. Net income per basic and fully diluted share was $0.03 for the first half of 2010 compared to a net loss per basic and fully diluted share of $8.03 for the first half of 2009. Weighted average fully-diluted shares outstanding increased by 68% from 16,746,112 shares in the first half of 2009 to 28,140,319 shares in the first half of 2010.

Capital Resources and Liquidity

Our business is capital intensive. Our ability to grow our reserve base is dependent upon our ability to obtain outside capital and generate cash flows from operating activities to fund our drilling and capital expenditures. Our cash flows from operating activities are substantially dependent upon crude oil and natural gas prices, and significant decreases in market prices of crude oil or natural gas could result in reductions of cash flow and affect our drilling and capital expenditure plan. To mitigate a portion of our exposure to fluctuations in natural gas prices, we have entered into natural gas swaps, three way collars, and put spreads.

We continually review our drilling and capital expenditure plans and may change the amount we spend based on industry conditions and the availability of capital. Our capital expenditure budget for 2010 is $175 million which will be used to drill and complete 22 H/B horizontal wells during 2010. In the first six months of 2010, our capital expenditures were $86.3 million of which

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$81.4 million was primarily for drilling and completing H/B horizontal wells and $4.9 million was related to infrastructure. We may continue to revise our capital expenditure budget during 2010 depending on our ability to continue to sublease two contracted Helmerich & Payne FlexRig3s™ that are currently on six month subleases to third parties through the end of September 2010 and January 2011, respectively, and our ability to enter into additional joint operating agreements (“JOA”) with other operators that have adjoining acreage to jointly develop Haynesville leasehold rights.

In order to protect the Company against the financial impact of a decline in natural gas prices, the Company has an active rolling three year hedging program. The Company has natural gas hedges in place of 7.2 Bcf or 74% of its remaining estimated natural gas production for 2010. In addition, the Company has 14.9 Bcf and 16.7 Bcf of natural gas hedged in 2011 and 2012, respectively, at average hedge prices of $6.14 and $6.08 per Mcf.

As of June 30, 2010, we had $26 million drawn on our revolving bank credit facility that has a borrowing base of $130 million. On July 8, 2010, we completed our semi-annual redetermination of our revolving bank credit facility borrowing base in which we reaffirmed the borrowing base of $130 million, extended the maturity date to August 1, 2012 which can be extended automatically to July 8, 2013 under certain circumstances and modified our Total Net Debt to EBITDA financial covenant. Our next semi-annual redetermination is scheduled for October 2010. As of June 30, 2010, we were in compliance with all financial covenants under our revolving bank credit facility.

Cash Flow—Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

In the six months ended June 30, 2010 and 2009, we spent $77.6 million and $112.4 million, respectively, in oil and natural gas acquisitions and development activities and related property and equipment, net of proceeds received from sales. These investments were funded during the six months ended June 30, 2010 by cash flow from operations, borrowing under our revolving bank credit facility and proceeds from the issuance of common stock and convertible notes in 2009. Cash flow provided by operating activities in the six months ended June 30, 2010 was $22.5 million compared to cash flow provided by operating activities in the six months ended June 30, 2009 of $20.6 million. The increase in net cash provided by operating activities in 2010 is primarily due to a decrease in accounts payable during 2009 which was the result of the Company decreasing drilling activity in response to lower natural gas prices.

Revolving Bank Credit Facility and Other Debt

Revolving Bank Credit Facility. We have a secured revolving bank credit facility, which matures on August 1, 2012 and provides for a line of credit of up to $250 million (the “commitment”), subject to a borrowing base which is based on a periodic evaluation of oil and gas reserves (“borrowing base”). The amount of credit available at any one time under the revolving bank credit facility is the lesser of the borrowing base or the amount of the commitment. In addition to the amendments described above under “Capital Resources and Liquidity,” the material terms of the credit facility are described in our 2009 10-K. The credit facility contains various affirmative and restrictive covenants. These covenants, among other things, prohibit additional indebtedness, sale of assets, mergers and consolidations, dividends and distributions, and changes in management and require the maintenance of various financial ratios. We were in compliance with all financial and nonfinancial covenants at June 30, 2010.

Convertible Notes. We issued $125 million of 5.00% convertible notes due 2013 in February 2008 and $86.25 million of 4.50% convertible notes due 2015 in October 2009 (collectively “convertible notes”). These convertible notes are unsecured. The terms of the convertible notes are more fully described in our 2009 10-K. We were in compliance with the terms of the convertible notes at June 30, 2010.

Working Capital

At June 30, 2010, we had a working capital deficit of $11.7 million. Including availability under our revolving bank credit facility, our working capital as of June 30, 2010 would have been $92.3 million.

Price Risk Management

See Part I, Item 3 – Quantitative and Qualitative Disclosure about Market Risk.

Critical Accounting Policies

Our critical accounting policies are summarized in our 2009 10-K. There have been no changes in those policies.

Contractual Obligations

As disclosed in the 2009 10-K, the Company has lease obligations related to four drilling rigs. During 2010, the Company subleased two of these drilling rigs for approximately six months. As a result of these subleases, the Company has reduced its future lease obligation by approximately $7.6 million.

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Recently Issued Accounting Standards

See Note A to our financial statements included in Part I, Item 1.

Forward-Looking Statements

All statements made in this document other than purely historical information are “forward looking statements” within the meaning of the federal securities laws. These statements reflect expectations and are based on historical operating trends, proved reserve positions and other currently available information. Forward-looking statements include statements regarding future plans and objectives, future exploration and development expenditures, the number and location of planned wells, the quality of our properties and potential reserve and production levels, and future revenue and cash flow. These statements may be preceded or followed by or otherwise include the words “believes”, “expects”, “anticipates”, “intends”, “continues”, “plans”, “estimates”, “projects”, “guidance” or similar expressions or statements that events “will” “should”, “could”, “might” or “may” occur. Except as otherwise specifically indicated, these statements assume that no significant changes will occur in the operating environment for oil and gas properties and that there will be no material acquisitions or divestitures except as otherwise described.

The forward-looking statements in this report are subject to all the risks and uncertainties which are described in our 2008 10-K and in this document. We may also make material acquisitions or divestitures or enter into financing transactions. None of these events can be predicted with certainty or taken into consideration in the forward-looking statements.

For all of these reasons, actual results may vary materially from the forward looking statements and we cannot assure you that the assumptions used are necessarily the most likely. We will not necessarily update any forward looking statements to reflect events or circumstances occurring after the date the statement is made except as may be required by federal securities laws.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

We are subject to price fluctuations for natural gas and crude oil. Prices received for natural gas and crude oil sold on the spot market are volatile due to factors beyond our control. Reductions in crude oil and natural gas prices could have a material adverse effect on our financial position, results of operations, capital expenditures and quantities of reserves recoverable on an economic basis. Any reduction in reserves, including reductions due to lower prices, can reduce our borrowing base under our revolving bank credit facility and adversely affect our liquidity and our ability to obtain capital for our acquisition and development activities.

To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into financial price risk management activities with respect to a portion of projected crude oil and natural gas production through financial price commodity swaps, collars and put spreads. Our revolving bank credit facility requires us to maintain a hedging program on mutually acceptable terms whenever the loan amount outstanding exceeds 75% of the borrowing base.

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Following is a summary of the outstanding crude oil and natural gas derivative contracts we have in place as of June 30, 2010:

Effective Date	Maturity Date	Notional Amount Per Month	Remaining Notional Amount as of June 30, 2010	Additional Put Options		Floor		Ceiling		Designation under ASC 815
Natural Gas (MMBtu):
1/1/2010	12/31/2010	452,667	2,716,000	$	5.00	$	7.50	$	—	Cash flow hedge
1/1/2010	12/31/2010	471,833	2,830,998	$	4.00	$	5.50	$	7.00	Cash flow hedge
1/1/2010	12/31/2010	25,000	150,000			$	—	$	8.50	Cash flow hedge
5/1/2010	12/31/2012	155,550	4,666,500			$	—	$	7.00	Cash flow hedge
5/1/2010	12/31/2010	271,667	1,630,000	$	4.00	$	6.00	$	—	Cash flow hedge
1/1/2011	12/31/2011	188,781	2,265,372			$	—	$	8.00	Cash flow hedge
1/1/2011	3/31/2011	200,000	600,000	$	5.00	$	7.00	$	7.25	Cash flow hedge
1/1/2011	3/31/2011	200,000	600,000			$	—	$	8.90	Cash flow hedge
4/1/2011	10/31/2011	200,000	1,400,000	$	5.00	$	6.50	$	8.30	Cash flow hedge
11/1/2011	3/31/2012	200,000	1,000,000	$	5.50	$	7.00	$	10.10	Cash flow hedge
1/1/2011	12/31/2012	1,021,666	24,520,000	$	4.00	$	6.00	$	—	Cash flow hedge
1/1/2011	12/31/2012	167,612	4,022,697	$	4.50	$	6.25	$	—	Cash flow hedge
Crude Oil (Bbls):
5/1/2010	12/31/2011	3,000	54,900			$	—	$	100.00	Not designated

Natural gas contracts are settled against Inside FERC—Houston Ship Channel Index Price or NYMEX. The Inside FERC—Houston Ship Channel Index Price and NYMEX have historically had a high degree of correlation with the actual prices received by the Company.

The fair value of our natural gas and oil derivative contracts in effect at June 30, 2010 was $36.1 million, of which $16.4 million is classified as a current asset and $19.7 million is classified as a long-term asset.

Based on the monthly notional amount for natural gas in effect at June 30, 2010, a hypothetical $1.00 increase in natural gas prices would have decreased the fair value from our natural gas swaps and options by $40.2 million and a $1.00 decrease in natural gas prices would have increased the fair value from our natural gas swaps and option by $43.2 million. Based on the monthly notional amount for crude oil in effect at June 30, 2010, a hypothetical $1.00 increase or decrease in oil prices would have no material impact on the fair value for our crude oil derivative contract.

Interest Rate Risk

As of June 30, 2010, we had $26.0 million of long-term debt outstanding under our revolving bank credit facility. The revolving bank credit facility matures in August 2012 and is governed by a borrowing base calculation that is redetermined periodically. We have the option to elect interest at either (a) a base rate tied to the greatest of (i) the prime rate as published inThe Wall Street Journal plus a margin ranging from 1% to 2% based on the amount of the loan outstanding in relation to the borrowing base, (ii) the federal funds rate plus a margin ranging from 3.25% to 4.75% based on the amount of the loan outstanding in relation to the borrowing base, or (iii) the one-month LIBO rate plus a margin ranging from 2.75% to 4.25% based on the amount of the loan outstanding in relation to the borrowing base (payable monthly), or (b) the LIBO rate plus a margin ranging from 2.75% to 4.25% based on the amount of the loan outstanding in relation to the borrowing base for a period of one, two or three months (payable at the end of such period). As a result, our interest costs fluctuate based on short-term interest rates relating to our revolving bank credit facility. Based on borrowings outstanding at June 30, 2010, a 100 basis point change in interest rates would change our annual interest expense by approximately $260,000. We had no interest rate derivatives during 2010.

Our $86.25 million of convertible notes and $125 million of convertible notes have fixed interest rates of 4.50% and 5.00%, respectively.

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ITEM 4. Controls and Procedures

Background. In March 2010, we identified a material weakness in our internal control over financial reporting due to management’s improper application of generally accepted accounting principles resulting in corrections to our previously reported consolidated financial statements as of and for the year ended December 31, 2008 and the first three quarters of 2009. Management failed to timely detect and correct errors relating to the improper application of generally accepted accounting principles in determining our full cost pool impairment charges, other impairment charges, and related deferred income taxes. Management also failed to timely detect and correct errors as a result of improperly including dilutive securities in our computation of diluted loss per share. Because of this material weakness, our management concluded that our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) and our internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)) were not effective as of December 31, 2009, and we included these conclusions in our 2009 10-K.

Evaluation of disclosure controls and procedures at June 30, 2010. Our principal executive officer and principal financial officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures as of June 30, 2010. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide us with reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosures. Based on that evaluation and due to the material weakness described above, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures continued not to be effective as of June 30, 2010.

Management, including our principal executive officer and our principal financial officer, has prepared and is in the process of implementing a plan to add additional qualified personnel and to reassign certain duties within the financial reporting department to ensure executive financial management has sufficient resources to properly research new and existing accounting guidance on a regular basis. Management believes this process will result in a more efficient internal control structure and effectively remedy the material weakness described above.

Changes in internal controls over financial reporting. There were no changes in our internal control over financial reporting that occurred during the period covered by this report 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

The Company is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to the Company and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, the Company’s estimates of the outcomes of such matters, and its experience in contesting, litigating, and settling similar financial position or results of operations after consideration of recorded accruals.

ITEM 1A. Risk Factors

There have been no material changes in the risk factors applicable to us from those disclosed in our 2009 10-K.

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

The following table presents information about repurchases of our common stock during the three months ended June 30, 2010.

Period	Total Number of Shares Purchased (1)	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans  or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
April 1, 2010 to April 30, 2010	—	$	—	—	—
May 1, 2010 to May 31, 2010	—		—	—	—
June 1, 2010 to June 30, 2010	31,161	$	6.25	—	—

⁽¹⁾ The number of shares of our common stock repurchased reflects the number of shares surrendered to the Company to pay withholding taxes in connection with the vesting of employee restricted stock awards.

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ITEM 3. Defaults Upon Senior Securities

None.

ITEM 4. Removed and Reserved

None.

ITEM 5. Other Information

None.

ITEM 6. Exhibits

See Exhibit Index.

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SIGNATURES

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

	GMX RESOURCES INC.
	(Registrant)
Date: August 6, 2010	/s/ James A. Merrill
	James A. Merrill
	Chief Financial Officer

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EXHIBIT INDEX

		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
3.1(a)	Amended and Restated Certificate of Incorporation of GMX Resources Inc.	SB-2	333-49328	3.1	11/06/2000
3.1(b)	Amended Certificate of Incorporation of GMX Resources Inc.	8-K	001-32977	3.1	05/25/2010
3.2	Amended and Restated Bylaws of GMX Resources Inc	8-K	001-32977	3.2	11/04/2008
3.3	Certificate of Designation of Series A Junior Participating Preferred Stock of GMX Resources Inc.	8-K	000-32325	3.1	05/18/2005
3.4	Certificate of Designation of 9.25% Series B Cumulative Preferred Stock	8-A12B	001-32977	4.1	08/08/2006
4.1(a)	Rights Agreement dated May 17, 2005 by and between GMX Resources Inc. and UMB Bank, N.A., as Rights Agent	8-K	000-32325	4.1	05/18/2005
4.1(b)	Amendment No. 1 to Rights Agreement dated February 1, 2008	8-A/A	001-32977	4.1	02/21/2008
4.1(c)	Amendment No. 2 to Rights Agreement dated October 30, 2008	8-A/A	001-32977	1	11/17/2008
4.2	Indenture dated February 15, 2008, between GMX Resources Inc. and The Bank of New York Trust Company, N.A., as trustee	8-K	001-32977	4.1	02/15/2008
4.3	Indenture dated October 28, 2009, between GMX Resources Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee	8-K	001-32977	4.1	10/28/2009
4.4	Supplemental Indenture dated October 28, 2009, between GMX Resources Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee	8-K	001-32977	4.2	10/28/2009
10.1	Amended and Restated 2008 Long-Term Incentive Plan	8-K	001-32977	10.1	05/25/2010
10.2	Fourth Amended and Restated Loan Agreement dated July 8, 2010, among GMX Resources Inc., Capital One, National Association, as Administrative Agent, and the lenders named therein.	8-K	001-32977	10.1	07/13/2010
31.1	Rule 13a-14(a) Certification of Chief Executive Officer		001-32977			*
31.2	Rule 13a-14(a) Certification of Chief Financial Officer		001-32977			*
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350		001-32977			*
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350		001-32977			*

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