GMX RESOURCES INC - FORM 10-Q

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EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350 - GMX RESOURCES INC	dex321.htm
EX-31.2 - RULE 13A-14(A) CERTIFICATION OF CHIEF FINANCIAL OFFICER - GMX RESOURCES INC	dex312.htm
EX-31.1 - RULE 13A-14(A) CERTIFICATION OF CHIEF EXECUTIVE OFFICER - GMX RESOURCES INC	dex311.htm
EX-32.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C. SECTION 1350 - GMX RESOURCES INC	dex322.htm

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 September 30, 2010

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

For the transition period from to

Commission File Number 001-32977

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 the definitions of “accelerated filer,” “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Check one:

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 November 9, 2010 was 30,903,103, 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 September 30, 2010

TABLE OF CONTENTS


PART I. FINANCIAL INFORMATION		3

ITEM 1.	Financial Statements (unaudited)	3

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	22

ITEM 4.	Controls and Procedures	23

PART II. OTHER INFORMATION		24

ITEM 1.	Legal Proceedings	24

ITEM 1A.	Risk Factors	24

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	25

ITEM 6.	Exhibits	25

SIGNATURES		26

EXHIBIT INDEX		27

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			September 30, 2010
	(as adjusted)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	35,554		$	4,069
Accounts receivable – interest owners		1,233			6,975
Accounts receivable – oil and natural gas revenues, net		9,340			6,242
Derivative instruments		12,252			21,978
Inventories		326			326
Prepaid expenses and deposits		4,506			5,386

Total current assets		63,211			44,976

OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD
Properties being amortized		756,412			859,945
Properties not subject to amortization		39,789			66,615
Less accumulated depreciation, depletion, and impairment		(464,872	)		(485,857	)

		331,329			440,703

PROPERTY AND EQUIPMENT, AT COST, NET		101,755			104,888
DERIVATIVE INSTRUMENTS		17,292			21,421
OTHER ASSETS		8,484			6,835

TOTAL ASSETS	$	522,071		$	618,823

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	19,180		$	23,986
Accrued expenses		12,907			19,827
Accrued interest		3,361			2,817
Revenue distributions payable		4,434			5,871
Current maturities of long-term debt		48			48

Total current liabilities		39,930			52,549

LONG-TERM DEBT, LESS CURRENT MATURITIES		190,230			258,801
DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS		16,299			12,751
OTHER LIABILITIES		7,151			7,335
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 30,903,103 shares issued and outstanding in 2010		31			31
Additional paid-in capital		522,645			527,977
Accumulated deficit		(284,745	)		(281,739	)
Accumulated other comprehensive income, net of taxes		8,447			19,161

Total GMX Resources’ equity		246,380			265,432
Noncontrolling interest		22,081			21,955

Total equity		268,461			287,387

TOTAL LIABILITIES AND EQUITY	$	522,071		$	618,823

See accompanying notes to consolidated financial statements.

GMX Resources Inc. and Subsidiaries

Consolidated Statements of Operations

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

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2010			2009			2010
	(as adjusted)						(as adjusted)
OIL AND GAS SALES, net of gain or (loss) from ineffectiveness of derivatives of $(72), $(116), $920, and $(1,373), respectively	$	23,075		$	24,833		$	68,737		$	69,346
EXPENSES:
Lease operations		2,708			2,790			8,581			8,144
Production and severance taxes		279			(578	)		(1,074	)		447
Depreciation, depletion, and amortization		7,752			9,602			23,252			24,704
Impairment of oil and natural gas properties		—			—			138,078			—
General and administrative		4,811			6,652			14,580			20,057

Total expenses		15,550			18,466			183,417			53,352

Income (loss) from operations		7,525			6,367			(114,680	)		15,994

NON-OPERATING INCOME (EXPENSES):
Interest expense		(4,388	)		(4,794	)		(12,540	)		(13,678	)
Interest and other income (expense)		4			(13	)		40			19
Unrealized gains (losses) on derivatives		(1,454	)		10			(2,827	)		(103	)

Total non-operating expense		(5,838	)		(4,797	)		(15,327	)		(13,762	)

Income (loss) before income taxes		1,687			1,570			(130,007	)		2,232

BENEFIT (PROVISION) FOR INCOME TAXES		(3,068	)		2,934			(3,594	)		6,354

NET INCOME (LOSS)		(1,381	)		4,504			(133,601	)		8,586
Net income attributable to noncontrolling interest		—			(1,180	)		—			(2,111	)

NET INCOME (LOSS) ATTRIBUTABLE TO GMX RESOURCES		(1,381	)		3,324			(133,601	)		6,475
Preferred stock dividends		(1,156	)		(1,156	)		(3,469	)		(3,469	)


NET INCOME (LOSS) APPLICABLE TO COMMON SHAREHOLDERS	$	(2,537	)	$	2,168		$	(137,070	)	$	3,006

EARNINGS (LOSS) PER SHARE – Basic	$	(0.12	)	$	0.08		$	(7.52	)	$	0.11

EARNINGS (LOSS) PER SHARE – Diluted	$	(0.12	)	$	0.08		$	(7.52	)	$	0.11

WEIGHTED AVERAGE COMMON SHARES – Basic		21,122,331			28,256,684			18,235,889			28,180,741

WEIGHTED AVERAGE COMMON SHARES – Diluted		21,122,331			28,267,781			18,235,889			28,249,495

See accompanying notes to consolidated financial statements.

GMX Resources Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(dollars in thousands)

(Unaudited)


	Nine Months Ended September 30,
	2009			2010
	(as adjusted)
CASH FLOWS DUE TO OPERATING ACTIVITIES
Net income (loss)	$	(133,601	)	$	8,586
Depreciation, depletion, and amortization		23,252			24,704
Impairment and other writedowns		138,078			—
Deferred income taxes		3,594			(6,324	)
Non-cash compensation expense		3,658			4,660
Non-cash interest expense		3,847			6,902
Unrealized losses on derivatives		2,392			1,476
Decrease (increase) in:
Accounts receivable		1,378			(2,643	)
Inventory and prepaid expenses		290			(1,891	)
Increase (decrease) in:
Accounts payable and accrued liabilities		207			5,668
Revenue distributions payable		(1,686	)		(166	)

Net cash provided by operating activities		41,409			40,972

CASH FLOWS DUE TO INVESTING ACTIVITIES
Purchase of oil and natural gas properties		(122,469	)		(129,877	)
Proceeds from sale of oil and natural gas properties		—			5,522
Purchase of property and equipment		(25,514	)		(8,684	)
Proceeds from sale of property and equipment		—			1,354

Net cash used in investing activities		(147,983	)		(131,685	)

CASH FLOW DUE TO FINANCING ACTIVITIES
Advances on revolving bank credit facility		99,000			65,000
Payments on debt		(55,069	)		(68	)
Proceeds from sale of common stock		65,264			—
Dividends paid on Series B preferred stock		(2,313	)		(3,469	)
Fees paid related to financing activities		(2,832	)		—
Contributions from non-controlling interest holders					1,165
Distributions to non-controlling interest holders		—			(3,400	)

Net cash provided by financing activities		104,050			59,228


NET DECREASE IN CASH		(2,524	)		(31,485	)

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		6,716			35,554

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	4,192		$	4,069

SUPPLEMENTAL CASH FLOW DISCLOSURE
CASH PAID DURING THE PERIOD FOR:
INTEREST, Net of amounts capitalized	$	5,283		$	9,177
INCOME TAXES, Paid (Received)	$	—		$	(30	)

See accompanying notes to consolidated financial statements.

GMX Resources Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income

(dollars in thousands)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2010			2009			2010
	(as adjusted)						(as adjusted)
Net income (loss)	$	(1,381	)	$	4,504		$	(133,601	)	$	8,586

Other comprehensive income (loss), net of income tax:
Change in fair value of derivative instruments, net of income tax of $(273), $4,904, $5,329, and $11,216, respectively		(530	)		9,519			10,345			21,773
Reclassification of gain on settled contracts, net of income tax of $(2,797), $(1,972), $(8,267), and $(5,700), respectively		(5,430	)		(3,828	)		(16,048	)		(11,064	)

Other comprehensive income (loss), net of income tax		(5,960	)		5,691			(5,703	)		10,709
Comprehensive income attributable to the noncontrolling interest		—			1,180			—			2,111

Comprehensive income (loss) attributable to GMX Resources shareholders	$	(7,341	)	$	9,015		$	(139,304	)	$	17,184

See accompanying notes to consolidated financial statements.

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and nine months ended September 30, 2009 and 2010

(Unaudited)

NOTE A – NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Nature of Business

GMX Resources Inc. and subsidiaries (collectively the “Company,” “GMXR,” “we” or “our”) is engaged primarily in natural gas and crude oil exploration, development and production in the Haynesville/Bossier Shale and Cotton Valley Sands of East Texas (the “core area”). GMXR owns drilling rigs exclusively for GMXR through a wholly owned subsidiary, Diamond Blue Drilling Co. Additionally, Endeavor Pipeline Inc. (“Endeavor Pipeline”), a wholly owned subsidiary, operates our gathering system in our core area. In November 2009, the gas gathering, compression and related equipment owned by Endeavor Pipeline was transferred to a newly formed entity, Endeavor Gathering, LLC (“Endeavor Gathering”), and a 40% membership interest in Endeavor Gathering was sold to a third party. Endeavor Gathering will provide firm capacity gathering services as well as development of future gathering infrastructure needs in support of GMXR’s operations in its core area. Endeavor Pipeline will continue to serve as the operator of the gathering facilities.

Basis of Presentation

The accompanying unaudited consolidated financial statements and condensed notes thereto of 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 audited 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 unaudited consolidated balance sheet of GMXR as of September 30, 2010, and the results of its operations for the three and nine months ended September 30, 2010 and 2009 and its cash flow for the nine months ended September 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. There were 11,097 and 68,754 dilutive shares related to the stock options and non-vested restricted stock awards as of the three and nine months ended September 30, 2010, respectively. Due to depressed share prices, there were no dilutive shares from the 5.00% convertible notes at September 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 nine months ended September 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 $5.7 million at December 31, 2009 and September 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 $58.6 million at September 30, 2010, we would have incurred a ceiling test writedown of $37.3 million for the nine months ended September 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.

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and nine months ended September 30, 2009 and 2010

(Unaudited)

Recent Accounting Standards

In October 2009, the Financial Accounting Standards Board (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 guidance also requires several disclosures including a description of the terms of the arrangement and the reason for entering into the arrangement. The effective dates of the guidance 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. For further discussion, see Note B.

A standard to improve disclosures about fair value measurements was issued by the FASB 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 standard also clarified existing disclosure requirements regarding the level of disaggregation of fair value measurements and disclosures regarding inputs and valuation techniques. We adopted all aspects of this standard effective as of the first quarter of 2010. The adoption had no impact on our consolidated financial position or results of operations.

In February 2010, the FASB amended guidance on subsequent events to alleviate potential conflicts between FASB guidance and Securities and Exchange Commission (“SEC”) requirements. Under this amended guidance, SEC filers are no longer required to disclose the date through which subsequent events have been evaluated in originally issued and revised financial statements. This guidance was effective immediately and we adopted these new requirements in first quarter 2010. The adoption of this guidance did not have an impact on our financial statements.

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 senior notes due 2013 (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.

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and nine months ended September 30, 2009 and 2010

(Unaudited)

On January 1, 2010, the Company was required to adopt ASU 2009-15, which changed 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 nine months ended September 30, 2009 were affected by the adoption:


	Three Months ended September 30, 2009
	As Reported			Adjustments			As Adjusted
	(in thousands)
NON-OPERATING INCOME (EXPENSES)
Interest expense	$	(4,229	)	$	(159	)	$	(4,388	)
NET LOSS	$	(1,222	)	$	(159	)	$	(1,381	)
NET LOSS APPLICABLE TO COMMON SHAREHOLDERS	$	(2,378	)	$	(159	)	$	(2,537	)
EARNINGS (LOSS) PER SHARE – BASIC	$	(0.11	)	$	(0.01	)	$	(0.12	)
EARNINGS (LOSS) PER SHARE – DILUTED	$	(0.11	)	$	(0.01	)	$	(0.12	)

	Nine Months ended September 30, 2009
	As Reported			Adjustments			As Adjusted
	(in thousands)
NON-OPERATING INCOME (EXPENSES)
Interest expense	$	(12,080	)	$	(460	)	$	(12,540	)
NET LOSS	$	(133,141	)	$	(460	)	$	(133,601	)
NET LOSS APPLICABLE TO COMMON SHAREHOLDERS	$	(136,610	)	$	(460	)	$	(137,070	)
EARNINGS (LOSS) PER SHARE – BASIC	$	(7.49	)	$	(.03	)	$	(7.52	)
EARNINGS (LOSS) PER SHARE – DILUTED	$	(7.49	)	$	(.03	)	$	(7.52	)

As of September 30, 2010, 2,640,000 shares of our common stock were subject to outstanding loans to the Share Borrower with a fair value of $12.8 million. The unamortized amount of issuance costs associated with the share lending agreement is $1.9 million at September 30, 2010, of which $0.8 million is classified as a current asset and $1.1 million is a long-term asset included in Other Assets. The Company recognized $0.5 million in interest expense relating to the amortization of the Share Lending Agreement for the nine months ended September 30, 2010.

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				September 30, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in thousands)
Revolving bank credit facility⁽¹⁾	$	—	$	—	$	65,000	$	65,000
5.00% Convertible Senior Notes due February 2013		115,646		111,406		117,765		100,313
4.50% Convertible Senior Notes due May 2015		73,187		87,652		74,708		54,338
Joint venture financing⁽²⁾		1,445		1,445		1,376		1,376

Total	$	190,278	$	200,503	$	258,849	$	221,027

⁽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.

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and nine months ended September 30, 2009 and 2010

(Unaudited)

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 September 30, 2010 are shown below:


Financial Covenant	Required Ratio	Actual Ratio
Current ratio ⁽¹⁾	Not less than 1 to 1	1.65 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	4.27 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	3.42 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 ($65 million as of September 30, 2010) to current liabilities. The calculation will not include the effects, if any, of derivatives under ASC 815. As of September 30, 2010, current assets included derivatives assets of $22.0 million. In addition, the 5.00% convertible notes and the 4.50% convertible senior notes due 2015 (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 September 30, 2010, none of the 5.00% convertible notes and the 4.50% convertible notes had been surrendered for conversion.

⁽²⁾	EBITDA is a non-GAAP number that is defined in our revolving bank credit facility and is calculated and reconciled as follows from the GAAP amount of net loss for the twelve months ended September 30, 2010 (amounts in thousands):


Net loss	$	(38,902	)
Plus:
Interest expense		17,887
Early extinguishment of debt		4,976
Impairment of oil and natural gas properties		50,072
Depreciation, depletion and amortization		32,457
Non-cash compensation and other expenses		4,553
Less:
Income tax benefit		(9,981	)

EBITDA	$	61,062

⁽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 obligations that should be treated as interest. For the twelve months ended September 30, 2010, cash interest expense included fees paid related to bank financing activities and other loan fees of $1.6 million. As of September 30, 2010, non-cash interest expense of $7.1 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 $2.4 million was added to interest expense.

As of September 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 September 30, 2010, we had $65 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 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 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 GAAP. 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.

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and nine months ended September 30, 2009 and 2010

(Unaudited)

5.00% Convertible Senior Notes

As of September 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		7,236

Carrying amount	$	117,764

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 nine months ended September 30, 2009 and 2010, interest costs on the convertible notes included $1.6 million and $4.7 million, respectively, relating to the contractual interest coupon. For the three and nine months ended September 30, 2009, interest costs were $0.8 million and $2.7 million, respectively related to the amortization of the debt discount and transaction costs. For the three and nine months ended September 30, 2010, these interest and transaction costs were $0.9 million and $2.7 million, respectively.

As of September 30, 2010, the unamortized discount is expected to be amortized into earnings over 2.3 years. The carrying value of the equity component of the 5.00% convertible notes was $9.3 million as of September 30, 2010.

4.50% Convertible Senior Notes

As of September 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		11,542

Carrying amount	$	74,708

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 nine months ended September 30, 2010 was $1.1 million and $3.0 million, respectively. The amount of non-cash interest expense for the three and nine months ended September 30, 2010 related to the amortization of the debt discount and transaction costs was $0.6 million and $1.9 million, respectively. The 4.50% convertible notes had not yet been issued at September 30, 2009. As of September 30, 2010, the unamortized discount is expected to be amortized into earnings over 4.6 years. The carrying value of the equity component of the 4.50% convertible notes was $8.4 million as of September 30, 2010.

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and nine months ended September 30, 2009 and 2010

(Unaudited)

NOTE D – DERIVATIVE ACTIVITIES

The Company is 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 the Company’s control. Reductions in crude oil and natural gas prices could have a material adverse effect on the Company’s 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 the Company’s borrowing base under the revolving bank credit facility and adversely affect the Company’s liquidity and ability to obtain capital for acquisition and development activities.

To mitigate a portion of its exposure to fluctuations in commodity prices, the Company enters into financial price risk management activities with respect to a portion of projected crude oil and natural gas production through financial price swaps, collars and put spreads (collectively “derivatives”). Additionally, the Company uses basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas due to the geographic price differentials between a given cash market location and the futures contract delivery locations. Settlement or expiration of the hedges is designed to coincide as closely as possible with the physical sale of the commodity being hedged—daily for oil and monthly for natural gas—to obtain reasonable assurance that a gain in the cash sale will offset the loss on the hedge and vice versa.

The Company’s revolving bank credit facility requires it to maintain a hedging program on mutually acceptable terms whenever the loan amount outstanding exceeds 75% of the borrowing base. The Company utilizes counterparties for our derivative instruments that are members of our lending bank group and that the Company believes are credit-worthy entities at the time the transactions are entered into. The Company closely monitors the credit ratings of these counterparties. Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. However, the recent events in the financial markets demonstrate there can be no assurance that a counterparty financial institution will be able to meet its obligations to the Company. Additionally, none of the Company’s derivative instruments contain credit-risk-related contingent features. However, the Company has not incurred any credit-related losses associated with derivative activities and believes that its counterparties will continue to be able to meet their obligations under these transactions.

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		September 30, 2010
		*(in thousands)*
Derivatives designated as Hedging Instruments under ASC 815
Natural gas	Current derivative assets	$	12,896	$	27,351
Natural gas	Derivative assets – non-current		19,144		25,866

Total derivative asset fair value		$	32,040	$	53,217



		Liability Fair Value
	Balance Sheet Location	December 31, 2009		September 30, 2010
		*(in thousands)*
Derivatives designated as Hedging Instruments under ASC 815
Natural gas	Current derivative assets	$	—	$	4,524
Natural gas basis	Current derivative assets		—		756
Natural gas	Derivative assets – non-current		549		3,994
Natural gas basis	Derivative assets – non-current		—		391

		$	549	$	9,665
Derivatives not designated as Hedging Instruments under ASC 815
Natural gas	Current derivative assets	$	374	$	—
Natural gas basis	Current derivative assets		270		—
Natural gas	Derivative assets – non-current		1,303		—
Crude oil	Current derivative assets		—		93
Crude oil	Derivative assets – non-current		—		60

		$	1,947	$	153

Total derivative liability fair value		$	2,496	$	9,818

Net derivative fair value		$	29,544	$	43,399

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and nine months ended September 30, 2009 and 2010

(Unaudited)

The following table summarizes the outstanding natural gas and crude oil derivative contracts the Company had in place as of September 30, 2010:


Effective Date	Maturity Date	Notional Amount Per Month		Remaining Notional Amount as of September 30, 2010		Additional Put Options		Floor		Ceiling		Designation under ASC 815
Natural Gas (MMBtu):
1/1/2010	12/31/2010		444,333		1,333,000	$	5.00	$	7.50	$	—	Cash flow hedge
1/1/2010	12/31/2010		471,833		1,415,499	$	4.00	$	5.50	$	7.00	Cash flow hedge
1/1/2010	12/31/2010		25,000		75,000			$	—	$	8.50	Cash flow hedge
5/1/2010	12/31/2012		155,456		4,197,300			$	—	$	7.00	Cash flow hedge
5/1/2010	12/31/2010		320,000		960,000	$	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		3,047		45,700			$	—	$	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 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.

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


	For the Three Months Ended September 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 (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
	*(in thousands)*				*(in thousands)*
Natural gas	$	(362	)	Oil and Gas Sales	$	7,753	$	(72	)
Crude oil		(442	)	Oil and Gas Sales		474		—

	$	(804	)		$	8,227	$	(72	)


	For the Nine Months Ended September 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 (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
	*(in thousands)*				*(in thousands)*
Natural gas	$	16,058		Oil and Gas Sales	$	22,393	$	920
Crude oil		(384	)	Oil and Gas Sales		1,922		—

	$	15,674			$	24,315	$	920

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and nine months ended September 30, 2009 and 2010

(Unaudited)


	For the Three Months Ended September 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 (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
	*(in thousands)*			*(in thousands)*
Natural gas	$	14,423	Oil and Gas Sales	$	5,800	$	(116	)


	For the Nine Months Ended September 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 (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
	*(in thousands)*			*(in thousands)*
Natural gas	$	32,989	Oil and Gas Sales	$	16,764	$	(1,373	)

Assuming that the market prices of oil and gas futures as of September 30, 2010 remain unchanged, the Company would expect to transfer a gain of approximately $22 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.

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 September 30, 2009				Nine Months Ended September 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	$	1,676		Oil and gas sales	$	4,415
Unrealized
Natural gas	Unrealized losses on derivatives		(1,443	)	Unrealized losses on derivatives		(2,757	)
Natural gas basis	Unrealized losses on derivatives		(13	)	Unrealized losses on derivatives		(70	)

		$	220			$	1,588

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and nine months ended September 30, 2009 and 2010

(Unaudited)


	Three Months Ended September 30, 2010			Nine Months Ended September 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		10	Unrealized losses on derivatives		118

		$	10		$	(80	)

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 September 30, 2010:


	As of December 31, 2009:						As of September 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	$	—	$	—	$	43,552		$	—
Crude oil derivative instruments	$	—	$	—	$	—	$	—	$	(153	)	$	—

NOTE E – STOCK COMPENSATION PLANS

We recognized $1.4 million and $1.1 million of stock compensation expense for the three months ended September 30, 2009 and 2010, respectively, and $3.7 million and $4.7 million for the nine months ended September 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 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 $0.2 million for the three months ended September 30, 2009 and 2010, respectively, and $0.7 million and $0.9 million for the nine months ended September 30, 2009 and 2010.

Restricted Stock

A summary of the status of our unvested shares of restricted stock and the changes for the years ended December 31, 2008 and 2009 and the nine months ended September 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		359,385		$	6.45
Vested		(220,016	)	$	25.64
Forfeited		(27,903	)	$	23.11

Unvested shares as of September 30, 2010		691,996		$	13.92

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three and nine months ended September 30, 2009 and 2010

(Unaudited)

As of September 30, 2010, there was $9.7 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 3.13 years.

NOTE F – CAPITAL STOCK

Share Lending Arrangement

During the nine months ended September 30, 2010, 500,000 shares issued and outstanding under the Company’s Share Lending Agreement were returned. For further discussion of the Company’s Share Lending Agreement, see Note B.

NOTE G – INCOME TAXES

We recorded tax provisions (benefits) of $3.0 million and $(2.9) million for the three months ended September 30, 2009 and 2010, respectively, and $3.6 million and $(6.3) million for the nine months ended September 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 September 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

Drilling Rig Lease Obligations

The Company has $90.5 million in lease obligations related to four drilling rigs as of September 30, 2010, which expire at various times through the year 2013. In 2010, the Company subleased one of these drilling rigs through January 2011 and another rig through January 2013. These subleases have reduced the Company’s future lease obligations by approximately $23.9 million as of September 30, 2010. Therefore, the Company’s net future lease obligation for these four drilling rigs was $66.6 million as of September 30, 2010.

Litigation

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.

The following information should be read in conjunction with our unaudited consolidated financial statements and the condensed notes thereto included in this quarterly report on Form 10-Q. The following information and such unaudited consolidated financial statements should also be read in conjunction with the financial statements and related notes, together with our discussion and analysis of financial position and results of operations, included in our annual report on Form 10-K for the year ended December 31, 2009 (the “2009 Form 10-K”). Unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean the business and operations of GMX Resources Inc. and its consolidated subsidiaries.

In addition, various statements contained in or incorporated by reference into this document that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements are subject to numerous assumptions and risks, including risks described in our 2009 Form 10-K, subsequent reports on Form 10-Q and in this report on Form 10-Q. Please read “Forward-Looking Statements” below.

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 prospective natural gas reserves to proved reserves, while maintaining balanced prudent financial management.

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

Summary Operating Data


	Three Months Ended September 30,					Nine Months Ended September 30,
	2009		2010			2009			2010
Production:
Oil (MBbls)		28		25			91			71
Natural gas (MMcf)		3,322		4,503			9,477			11,734
Gas equivalent production (MMcfe)		3,491		4,654			10,024			12,161
Average daily production (MMcfe/d)		37.9		51.1			36.7			44.7

Average Sales Price:

Oil (per Bbl)
Wellhead price	$	63.93	$	73.65		$	51.18		$	75.00
Effect of hedges, excluding gain or loss from ineffectiveness of derivatives		16.89		—			21.11			—

Total	$	80.82	$	73.65		$	72.29		$	75.00

Natural gas (per Mcf)
Wellhead price	$	3.44	$	3.84		$	3.63		$	4.14
Effect of hedges, excluding gain or loss from ineffectiveness of derivatives		2.84		1.29			2.83			1.43

Total	$	6.28	$	5.13		$	6.46		$	5.57

Average sales price, excluding gain or loss from ineffectiveness of derivatives (per Mcfe)	$	6.63	$	5.36		$	6.77		$	5.82
Operating and Overhead Costs (per Mcfe):
Lease operations expenses	$	0.78	$	0.60		$	0.86		$	0.67
Production and severance taxes		0.08		(0.12	)		(0.11	)		0.04
General and administrative		1.38		1.43			1.45			1.65
Depreciation, depletion and amortization—oil and natural gas properties	$	1.68	$	1.77		$	1.75		$	1.73

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

Oil and Natural Gas Sales. Oil and natural gas sales during the three months ended September 30, 2010 increased 8% to $24.8 million compared to $23.1 million for the three months ended September 30, 2009. Ineffectiveness of derivatives losses recognized in oil and gas sales of $72,000 and $116,000 for the three months ended September 30, 2009 and 2010, respectively, is the result of a difference

in the fair value of our cash flow hedges and the fair value of the projected cash flows of a hypothetical derivative based on our expected sales point. The increase in oil and natural gas sales was due to a 33% increase in production on a Bcfe-basis offset by a 19% 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 September 30, 2010 was $73.65 and $5.13, respectively, compared to $80.82 and $6.28, respectively, in the three months ended September 30, 2009. Production of oil for the three months ended September 30, 2010 decreased to 25 MBbls compared to 28 MBbls for the three months ended September 30, 2009, a decrease of 11%. Natural gas production for the three months ended September 30, 2010 increased to 4,503 MMcf compared to 3,322 MMcf for the three months ended September 30, 2009, an increase of 36%. The increase in natural gas production resulted from production related to 23 producing Haynesville/Bossier (“H/B”) horizontal wells that were on-line during 2010. During the third quarter of 2010, we brought on-line three H/B horizontal wells and production from H/B horizontal wells accounted for 64% of total production for the three months ended September 30, 2010 compared to 40% in the same period in 2009.

For the three months ended September 30, 2010, as a result of hedging activities but excluding derivative ineffectiveness, we recognized an increase in natural gas sales of $5.8 million compared to an increase in natural gas and oil sales of $9.4 million and $0.5 million, respectively, in the third quarter of 2009. In the third quarter of 2010, hedging, excluding ineffectiveness, increased the average natural gas sales price by $1.29 per Mcf compared to an increase in natural gas and oil sales price of $2.84 per Mcf and $16.89 per Bbl, respectively, in the third quarter of 2009. The Company did not recognize any oil related hedging activities in oil and gas sales in the three months ended September 30, 2010.

Lease Operations. Lease operations expenses increased $0.1 million, or 3%, for the three months ended September 30, 2010 to $2.8 million, compared to $2.7 million for the three months ended September 30, 2009. Lease operations expenses on an equivalent unit of production basis decreased $0.18 per Mcfe in the three months ended September 30, 2010 to $0.60 per Mcfe, compared to $0.78 per Mcfe for the three months ended September 30, 2009. The decrease in lease operations expenses on an equivalent unit basis resulted from an increase in H/B horizontal well production and cost control measures implemented by us during 2010. With little to no incremental increase in lease operations 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 operations costs.

Production and Severance Taxes. The State of Texas grants an exemption of severance taxes for wells that qualify as “high cost” wells. Certain wells, including all of our H/B wells, qualify for full severance tax relief for a period of ten years or recovery of 50% of the cost of drilling and completions, whichever is less. As a result, refunds for severance tax paid to the State of Texas on wells that qualify for reimbursement are recognized as accounts receivable and offset severance tax expense for the amount refundable. Production and severance taxes decreased 307% to a benefit of $0.6 million in the three months ended September 30, 2010 compared to an expense of $0.3 million in the three months ended September 30, 2009, as a result of the Company recording production and severance tax refunds of $1.5 million.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $1.8 million, or 24%, to $9.6 million in the three months ended September 30, 2010 compared to $7.8 million for the three months ended September 30, 2009. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.77 per Mcfe in the three months ended September 30, 2010 compared to $1.68 per Mcfe in the three months ended September 30, 2009. This increase in the rate per Mcfe is due to the percentage increase in oil and gas properties subject to amortization exceeding the percentage growth in reserves for the three months ended September 30, 2010.

General and Administrative Expense. General and administrative expense for the three months ended September 30, 2010 was $6.7 million compared to $4.8 million for the three months ended September 30, 2009, an increase of $1.9 million or 38%. General and administrative expense per equivalent unit of production was $1.43 per Mcfe for the third quarter of 2010 compared to $1.38 per Mcfe for the comparable period in 2009. This increase is primarily a result of our recognition of an increase of $1.2 million of payroll expenses related to the hiring of additional personnel compared to the same period in prior year. In addition, there were general increases of $0.7 million in other general and administrative expenses (office expenses, professional fees, travel, etc.). General and administrative expenses include $1.1 million and $1.4 million or of non-cash compensation expense as of the three months ended September 30, 2010 and 2009, respectively. Non-cash compensation represented 18% and 29% of total general and administrative expenses for the three months ended September 30, 2010 and 2009, respectively. 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. We expect general and administrative expenses on a per Mcfe basis to decrease as production increases, excluding any non-cash compensation expense from stock based compensation plans.

Interest. Interest expense for the three months ended September 30, 2010 was $4.8 million compared to $4.4 million for the same period in 2009. For the three months ended September 30, 2010 and 2009, interest expense includes non-cash interest expense of $2.4 million and $1.4 million, respectively. As a result of the accounting for convertible bonds, Share Lending Agreement and deferred premiums on derivative instruments, our non-cash interest expense related to these financial instruments was $1.9 million and $1.0 million for the three months ended September 30, 2010 and 2009, respectively. Cash interest expense for the three months ended September 30, 2010 and 2009 was $3.2 million and $3.5 million, respectively. The decrease in cash interest expense of $0.3 million is due to the reduction in borrowing under our revolving credit facility in the three months ended September 30, 2010 compared to the same period in 2009.

Income Taxes. Income tax for the three months ended September 30, 2010 was a benefit of $2.9 million as compared to a provision of $3.0 million in the same period in 2009. The income tax provision recognized in the three months ended September 30, 2009 was a result of an increase in the valuation allowance on net deferred tax assets. The benefit in the three months ended September 30, 2010 was 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 $1.2 million or $0.25 per Mefe in the three months ended September 30, 2009.

Results of Operations for the Nine Months Ended September 30, 2010 Compared to the Nine Months Ended September 30, 2009

Oil and Natural Gas Sales. Oil and natural gas sales in the nine months ended September 30, 2010 increased 1% to $69.3 million compared to $68.7 million for the nine months ended September 30, 2009. Excluding the non-cash effects of ineffectiveness from derivatives, oil and gas sales increased 4% from the first nine months of 2009 compared to the first nine months of 2010. Ineffectiveness of derivatives recognized in oil and gas sales of $0.9 million and $(1.4) million for the nine months ended September 30, 2009 and 2010, respectively, is the result of a difference in the fair value of our cash flow hedges and the fair value of the projected cash flows of a hypothetical derivative based on our expected sales point. The increase in sales, excluding ineffectiveness of derivatives, was due to a 21% increase in production offset by a 14% 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 nine months ended September 30, 2010 was $75.00 and $5.57, respectively, compared to $72.29 and $6.46, respectively, for the nine months ended September 30, 2009. Production of oil for the nine months ended September 30, 2010 decreased to 71 MBbls compared to 91 MBbls for the nine months ended September 30, 2009, a decrease of 22%. Natural gas production for the nine months ended September 30, 2010 increased to 11,734 MMcf compared to 9,477 MMcf for the nine months ended September 30, 2009, an increase of 24%. The increase in natural gas production resulted from production related to 23 producing H/B horizontal wells that were on-line during 2010. During the first nine months of 2010, we brought on-line 11 H/B horizontal wells and production from H/B horizontal wells accounted for 58% of total production in the first nine months of 2010 compared to 29% in the first nine months of 2009.

In the nine months ended September 30, 2010, as a result of hedging activities but excluding derivative ineffectiveness, we recognized an increase in natural gas sales of $16.7 million compared to an increase in natural gas and oil sales of $26.8 million and $1.9 million, respectively, in the first nine months of 2009. In the first nine months of 2010, hedging, excluding ineffectiveness, increased the average natural gas sales price by $1.43 per Mcf compared to an increase in natural gas and oil sales price of $2.83 per Mcf and $21.11 per Bbl, respectively, in the first nine months of 2009. We did not recognize any oil related hedging activities in oil and gas sales in the first nine months of 2010.

Lease Operations. Lease operations expense decreased $0.5 million, or 5%, in the nine months ended September 30, 2010 to $8.1 million, compared to $8.6 million in the nine months ended September 30, 2009. Lease operations expense on an equivalent unit of production basis decreased $0.19 per Mcfe in the nine months ended September 30, 2010 to $0.67 per Mcfe, compared to $0.86 per Mcfe for the nine months ended September 30, 2009. The decrease in lease operations expenses on an equivalent unit basis resulted from an increase in H/B horizontal well production and cost control measures implemented by us during the first nine months of 2010. With little to no incremental increase in lease operations 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 operations costs.

Production and Severance Taxes. The State of Texas grants an exemption of severance taxes for wells that qualify as “high cost” wells. Certain wells, including all of our H/B wells, qualify for severance tax relief for a period of ten years or recovery of 50% of the cost of drilling and completions, whichever is less. As a result, refunds for severance taxes paid to the State of Texas on wells that qualify for reimbursement are recognized as accounts receivable and offset severance tax expense for the amount refundable. For the nine months ended September 30, 2010, we recorded severance tax refunds of approximately $1.5 million. Production and severance taxes decreased from $1.1 million in expense for the nine months ended September 30, 2009 to income of $0.4 million in the nine months ended September 30, 2010, as a result of these refunds being recognized.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $1.4 million, or 6%, to $24.7 million in the nine months ended September 30, 2010 compared to $23.3 million for the nine months ended September 30, 2009. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.73 per Mcfe in the nine months ended September 30, 2010 compared to $1.75 per Mcfe in the nine months ended September 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 nine months ended September 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 nine months of 2009. We did not have any impairment charge on oil and gas properties in the first nine months of 2010, but we may be required to recognize impairment charges or writedowns in future reporting periods if market prices for oil or natural gas decline.

General and Administrative Expense. General and administrative expense for the nine months ended September 30, 2010 was $20.1 million compared to $14.6 million for the nine months ended September 30, 2009, an increase of $5.5 million, or 38%. The increase is a result of general increases of $1.5 million in general and administrative expenses (office expenses, professional fees, travel, etc.) and $4.0 million in additional payroll and stock-based compensation expense, partly due to an increase in severance costs of $1.5 million recorded for the nine months ended September 30, 2010, of which $0.9 million was a non-cash expense. General and administrative expense per equivalent unit of production was $1.65 per Mcfe for the first nine months of 2010 compared to $1.45 per Mcfe for the comparable period in 2009. A significant portion of our general and administrative expense is related to non-cash compensation expense. Non-cash compensation was $4.7 million and $3.7 million as of September 30, 2010 and 2009, respectively. Non-cash compensation represented 23% and 25% of total general and administrative expenses for the nine months ended September 30, 2010 and 2009, respectively. 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, we added key employees to execute a H/B horizontal drilling program. As a result, personnel costs have increased during the first nine months of 2010 compared to the same period in 2009.

Interest. Interest expense for the first nine months of 2010 was $13.7 million compared to $12.5 million for the first nine months of 2009. For the nine months ended September 30, 2010 and 2009, interest expense includes non-cash interest expense of $6.9 million and $3.8 million, respectively. As a result of the accounting for convertible bonds, share lending agreement and deferred premiums on derivative instruments, our non-cash interest expense related to these financial instruments was $5.7 million and $3.1 million for the nine months ended September 30, 2010 and 2009, respectively. Cash interest expense for the three months ended September 30, 2010 and 2009 was $8.6 million and $9.9 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 nine months of 2010 compared to the first nine months of 2009.

Income Taxes. Income tax for the nine months ended September 30, 2010 was a benefit of $6.3 million as compared to a provision of $3.6 million in the first nine months of 2009. The income taxes recognized in the first nine 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 $2.1 million or $0.17 per Mefe in the nine months ended September 30, 2009.

Net Income and Net Income Per Share

Net Income and Net Income Per Share—Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009. For the three months ended September 30, 2010 we reported net income applicable to common shareholders of $2.2 million and for the three months ended September 30, 2009, we reported a net loss applicable to common shareholders of $2.5 million. Net income per basic and fully diluted share was $0.08 for the third quarter of 2010 compared to a net loss per basic and fully diluted share of $0.12 for the third quarter of 2009. Weighted average fully-diluted shares outstanding increased by 34% from 21,122,331 shares in the third quarter of 2009 to 28,267,781 shares in the third quarter of 2010.

Net Income and Net Income Per Share—Nine months Ended September 30, 2010 Compared to Nine months Ended September 30, 2009. For the nine months ended September 30, 2010 we reported a net income applicable to common shareholders of $3.0 million and for the nine months ended September 30, 2009, we reported a net loss applicable to common shareholders of $137.1 million. Net income per basic and fully diluted share was $0.11 for the first nine months of 2010 compared to a net loss per basic and fully diluted share of $7.52 for the first nine months of 2009. Weighted average fully-diluted shares outstanding increased by 55% from 18,235,889 shares in the first nine months of 2009 to 28,249,495 shares in the nine months 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.

As of September 30, 2010, we had cash and cash equivalents of $4.1 million and a working capital deficit of $7.6 million. Through the period ended September 30, 2010, we have funded our operating expenses and capital expenditures through positive operating cash flows and financing of $65 million on our revolving bank credit facility. Prior to 2010, we have historically generated cash through the same means and received financing from our 5.00% convertible notes and our 4.5% convertible notes, which currently have carrying values of $117.8 million and $74.7 million, respectively, as of September 30, 2010.

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. In the first nine months of 2010, our capital expenditures were $136.8 million of which $130.4 million was primarily used for drilling and completing H/B horizontal wells, H/B acreage acquisitions, land related activities and infrastructure.

We may continue to revise our capital expenditures during 2010 and 2011 depending on our ability to continue to sublease two or more of our contracted Helmerich & Payne FlexRigs^™ (“FlexRigs”) and the availability of stimulation services used to complete our H/B Hz wells. We continue to seek additional frac dates through multiple service companies. Our capital expenditures, production and revenues could all vary if we are able to obtain additional frac dates during the fourth quarter of 2010.

The Company previously announced its intent to sublease an additional FlexRig3^™ in our fleet in order to more properly align our drilling efficiencies with available stimulation services and to manage our liquidity. Currently, the Company is drilling with two (Rig 1 and Rig 2) of its four contracted FlexRig3 rigs and has the other two rigs (Rig 3 and Rig 4) on sublease contracts. The sublease contract for Rig 4 expires in March 2013 and the agreement for Rig 3 expires in January 2011. The Company expects to complete a new sublease agreement for Rig 2 that will run from January 2011 until July 2011 with an option to extend six months until December 2011. Rig 3 due back in January 2011 will be re-subleased until April 2012. These two new leases will allow the Company to run one rig from January 2011 until at least July 2011.

In order to protect us against the financial impact of a decline in natural gas prices, we have an active, rolling three-year hedging program. We have natural gas hedges in place of 3.7 Bcf for our remaining estimated natural gas production for 2010 at an average hedge floor price of $6.35 per Mcf. In addition, we have 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 September 30, 2010, we have also sold put options that would reduce the average hedge floor price if the monthly natural gas contract settlement price is below $4.36 for the fourth quarter of 2010, $4.22 for 2011 and $4.13 for 2012. If the monthly natural gas contract settlement is below the average sold put price, we will receive the monthly natural gas contract settlement price plus $1.99 in 2010, $1.92 in 2011, and $1.95 in 2012. For further discussion of our derivative instruments, please also read Note D to the notes to unaudited financial statements included in this report.

Cash Flow—Nine months Ended September 30, 2010 Compared to Nine months Ended September 30, 2009

In the nine months ended September 30, 2010 and 2009, we spent $131.7 million and $148.0 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 nine months ended September 30, 2010 by cash flow from operations, borrowing under our revolving bank credit facility, along with the foregoing and with proceeds from the issuance of common stock and convertible notes in 2009. Cash flow provided by operating activities in the nine months ended September 30, 2010 was $41.0 million compared to $41.4 million in the nine months ended September 30, 2009.

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.

As of September 30, 2010, we had $65 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 to be completed in November 2010. The revolving 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 under our revolving credit facility at September 30, 2010. For further discussion of our revolving credit facility, please also read Note C to the notes to unaudited financial statements included in this report.

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. We were in compliance with the terms of the convertible notes at September 30, 2010. For further discussion of our convertible notes, please also read Note C to the notes to unaudited financial statements included in this report.

Working Capital

At September 30, 2010, we had a working capital deficit of $7.6 million. Including availability under our revolving bank credit facility, our working capital as of September 30, 2010 would have been $57.4 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, we have lease obligations related to four drilling rigs. During 2010, we subleased two of these drilling to third parties through January, 2011, and March, 2013. As a result of these subleases, we have reduced our future lease obligation by approximately $23.9 million.

Recently Issued Accounting Standards

See Note A to our financial statements included in Part I, Item 1 of this quarterly report.

Off-Balance Sheet Arrangements

We do not currently have any off-balance sheet arrangements.

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 2009 10-K and our quarterly reports on Form 10-Q filed thereafter, including in this report. 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.

The United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation was signed into law by the President on July, 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivate instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure its existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

The following table summarizes the outstanding crude oil and natural gas derivative contracts we had in place as of September 30, 2010:


Effective Date	Maturity Date		Notional Amount Per Month		Remaining Notional Amount as of September 30, 2010		Additional Put Options		Floor		Ceiling		Designation under ASC 815
Natural Gas (MMBtu):
1/1/2010		12/31/2010		444,333		1,333,000	$	5.00	$	7.50	$	—		Cash flow hedge
1/1/2010		12/31/2010		471,833		1,415,499	$	4.00	$	5.50	$	7.00		Cash flow hedge
1/1/2010		12/31/2010		25,000		75,000			$	—	$	8.50		Cash flow hedge
5/1/2010		12/31/2012		155,456		4,197,300			$	—	$	7.00		Cash flow hedge
5/1/2010		12/31/2010		320,000		960,000	$	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		3,047		45,700			$	—	$	100.00		Not designated

The fair value of our natural gas and oil derivative contracts in effect at September 30, 2010 was $43.4 million, of which $22.0 million is classified as a current asset and $21.4 million is classified as a long-term asset.

Based on the monthly notional amount for natural gas in effect at September 30, 2010, a hypothetical $0.10 increase in natural gas prices would have decreased the fair value from our natural gas swaps and options by $3.8 million and a $0.10 decrease in natural gas prices would have increased the fair value from our natural gas swaps and option by $3.8 million. Based on the monthly notional amount for crude oil in effect at September 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 September 30, 2010, we had $65.0 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 in The 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 September 30, 2010, a 100 basis point change in interest rates would change our annual interest expense by approximately $650,000. We had no interest rate derivatives during 2010.

Our $86.25 million of convertible notes due May, 2015, and $125 million of convertible notes due February, 2013, have fixed interest rates of 4.50% and 5.00%, respectively.

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.

To address the material weakness described above, management, including our principal executive officer and our principal financial officer, prepared and implemented 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 and implement new and existing accounting guidance on a regular basis. As of September 30, 2010, qualified personnel have been added and duties have been reassigned.

Evaluation of disclosure controls and procedures as of September 30, 2010. As of the end of the period covered by this quarterly report, we have evaluated, and under the supervision and with the participation of senior management, including our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15(b) of the Exchange Act. 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 this evaluation, as of the end of the period covered by this report, our principal executive officer and our principal financial officer have concluded that our disclosure controls and procedures were effective.

Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) 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, other than those changes noted above to address the material weaknesses as of December 31, 2009.

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

Except as set forth below, there have been no material changes in the risk factors applicable to us from those disclosed in our 2009 10-K.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas and other hydrocarbon products that we transport, store or otherwise handle in connection with our transportation, storage, and midstream services.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA recently adopted two sets of regulations addressing greenhouse gas emissions under the Clean Air Act. The first limits emissions of greenhouse gases from motor vehicles beginning with the 2012 model year. EPA has asserted that these final motor vehicle greenhouse gas emission standards trigger Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards take effect on January 2, 2011. On June 3, 2010, EPA published its final rule to address the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their greenhouse gas emissions will be required to also reduce those emissions according to “best available control technology” standards for greenhouse gases that have yet to be developed. Any regulatory or permitting obligation that limits emissions of greenhouse gases could require us to incur costs to reduce emissions of greenhouse gases associated with our operations and also adversely affect demand for the oil and natural gas that we produce.

In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas sources in the United States on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. Recently, in April 2010, the EPA proposed to expand its greenhouse gas reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. If the proposed rule is finalized as proposed, reporting of greenhouse gas emissions from such facilities, including many of our facilities, would be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011.

In June 2009, the United States House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap on emissions of greenhouse gases in the United States and would require most sources of greenhouse gas emissions to obtain and hold “allowances” corresponding to their annual emissions of greenhouse gases. By steadily reducing the number of available allowances over time, ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80 percent reduction of such emissions by 2050. Legislation to reduce emissions of greenhouse gases by comparable amounts is currently pending in the United States Senate, and more than one-third of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The passage of legislation that limits emissions of greenhouse gases from our equipment and operations could require us to incur costs to reduce the greenhouse gas emissions from our own operations, and it could also adversely affect demand for the oil and natural gas that we produce.

Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or rising waters, or increased costs for insurance.

Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays incurred by customers in the production of oil and natural gas, including from the developing shale plays. A decline in drilling of new wells and related servicing activities caused by these initiatives could adversely affect our financial position, results of operations and cash flows.

Proposals have been introduced in the U.S. Congress to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used in fracturing fluids by the oil and natural gas industry under the federal Safe Drinking Water Act (“SDWA”) and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, Emergency Planning and Community Right-to-Know Act (“EPCRA”), or other authority. Hydraulic fracturing is an important and commonly used process in the completion of unconventional oil and natural gas wells in shale, coalbed and tight sand formations. Sponsors of these bills, which are currently being considered in the legislative process, including in the House Energy and Commerce Committee and the Senate Environmental and Public Works Committee, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and otherwise cause adverse environmental impacts. The Chairman of the House Energy and Commerce Committee has initiated an investigation of the potential impacts of hydraulic fracturing, which has involved seeking information about fracturing activities and chemicals from certain companies in the oil and gas sector. In addition, in March 2010, the U.S. EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of crude oil and natural gas, including from the developing shale plays, incurred by our customers or could make it more difficult to perform hydraulic fracturing. If these legislative and regulatory initiatives cause a material decrease in the drilling of new wells and related servicing activities, our profitability could be materially impacted.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the CFTC and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure its existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable. We are at risk unless and until the CFTC adopts rules and definitions that confirm that companies such as ourselves are not required to post cash collateral for our derivative hedging contracts. In addition, even if we ourselves are not required to post cash collateral for our derivative contracts, the banks and other derivatives dealers who are our contractual counterparties will be required to comply with the Act’s new requirements, and the costs of their compliance will likely be passed on to customers such as ourselves, thus decreasing the benefits to us of hedging transactions and reducing our profitability.

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 September 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
July 1, 2010 to July 31, 2010		56,178	$	6.36		—		—
August 1, 2010 to August 31, 2010		—		—		—		—
September 1, 2010 to September 30, 2010		1,086	$	4.74		—		—

⁽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.

ITEM 6.

Exhibits

See Exhibit Index.

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.


		*GMX RESOURCES INC.*

Date: November 9, 2010		/s/ James A. Merrill
		James A. Merrill
		Chief Financial Officer

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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