NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Nature of Business

GMX Resources Inc. and its subsidiaries (collectively, "GMX," the “Company”, “we,” “us” and “our”) is an independent oil and natural gas exploration and production company historically focused on the development of the Cotton Valley group of formations, specifically the Cotton Valley Sands layer in the Schuler formation and the Upper Bossier, Middle Bossier and Haynesville/Lower Bossier layers of the Bossier formation (the “Haynesville/Bossier Shale”), in the Sabine Uplift of the Carthage, North Field of Harrison and Panola counties of East Texas (our “primary development area”).

During 2010, we made a strategic decision to pursue properties that would expand our assets and development into other basins, diversify our company’s concentrated natural gas focus from two resource plays in one basin and provide the Company more liquid hydrocarbon opportunities. These efforts have led to successful agreements entered into during the first half of 2011 to acquire core positions in over 75,000 net acres in two of the leading oil resource plays in the U.S. In January 2011, the Company entered into five transactions to purchase undeveloped leasehold in the very successful and competitive region located in the Williston Basin of North Dakota/Montana, targeting the Bakken/Sanish-Three Forks Formation, and in the oil window of the Denver Julesburg Basin (the “DJ Basin”) of Wyoming, targeting the emerging Niobrara Formation. In May 2011, the Company increased its Williston Basin position with multiple transactions totaling 11,449 net acres. With the acquisition of the liquids-rich (estimated 90% oil) Bakken and Niobrara acreage, we will have better flexibility to deploy capital based on a variety of economic and technical factors, including well costs, service availability, take-away capacity and commodity prices (including differentials applicable to the basin). We believe this flexibility will enable us to generate better cash flow growth to fund our capital expenditure program. We believe our experienced Rockies and Haynesville/Bossier Shale horizontal drilling personnel will enable us to succeed in the development of these new oil resource plays. A summary of the 2011 transactions are as follows:

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Niobrara acquisition—On February 14, 2011, the Company acquired all of the working interest and an 80% net revenue interest in approximately 30,818 undeveloped net acres of oil and gas leases located in the Niobrara basin in Wyoming for approximately $27.4 million, including commissions. Pursuant to our agreement with the seller, the seller has elected not to exercise an option to reacquire 50% of the working interest acquired by us in these properties at the same purchase price paid by us.

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Bakken acquisition-Retamco—On January 13, 2011, we entered into a purchase and sale agreement relating to the acquisition by the Company of all of the working interest and an 80% net revenue interest in approximately 17,797 undeveloped net acres of oil and gas leases located in the Bakken formation in Montana and North Dakota. Pursuant to this agreement, as consideration for the oil and gas leases, we issued to the seller, Retamco Operating, Inc., at the closing of this transaction on February 28, 2011, 2,268,971 shares of common stock and approximately $4.2 million in cash. At the closing, the Company also entered into a registration rights agreement with this seller relating to the resale of the shares of common stock received in this transaction.

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Niobrara acquisition-Retamco—On January 13, 2011, we entered into a separate purchase and sale agreement with Retamco Operating, Inc. relating to the acquisition by the Company of all of the working interest and an 80% net revenue interest in approximately 9,374 undeveloped net acres of oil and gas leases located in the Niobrara basin in Wyoming. The purchase price for this transaction was approximately $24.0 million in cash. On April 6, 2011, we completed the purchase of 9,039 acres and the remaining 335 net acres in May 2011.

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Bakken acquisitions-Arkoma Bakken and other parties—On April 28, 2011, the Company acquired an undivided 87.5% of the sellers’ working interest and an 82.5% net revenue interest in approximately 7,613 undeveloped acres located in McKenzie and Dunn Counties, North Dakota (with the acquired interest representing 6,661 net acres). The aggregate purchase price for these properties was approximately $31.2 million, of which approximately $10.4 million was paid in cash and the remainder of the purchase price was paid with stock consideration of 3,542,091 common shares (based on a 15 day volume weighted average value of $5.88 per share). At closing, the Company entered into a participation agreement with a joint operating agreement designating the Company as the operator of these properties. The Company has entered into a registration rights agreement with these sellers at closing relating to the resale of the shares of common stock received in this transaction. However, these sellers have agreed not to sell the shares of common stock received by them for six months following the closing of this transaction.

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May 2011 Bakken acquisitions - In May 2011, the Company increased its Williston Basin position with multiple transactions totaling 11,449 net acres for a total purchase price of $28 million. The first of two significant transactions was a purchase and sale agreement for 9,608 net acres at an average cost of $2,500 per acre, from a private seller, located in Billings and Stark Counties, North Dakota. The second transaction was for 1,684 net acres from the State of North Dakota at an average cost of $2,211 per acre. Approximately 960 net acres are located in McKenzie County and 724 net acres are located in Billings County. The remaining 157 net acres were acquired through the leasing of several fee mineral rights.

The two Bakken acquisitions in May 2011 bring our total Williston Basin net acres to approximately 35,524. We hold Williston Basin leases in approximately 150 1,280-acre units and expect to be the operator in approximately 43 of those units, providing a minimum of 172 operated locations. We expect that the average working interest in our Williston Basin operated locations to be approximately 75%, with the first three operated wells having an 52%-100% working interest.

We have three subsidiaries: Diamond Blue Drilling Co. (“Diamond Blue”), Endeavor Pipeline Inc. (“Endeavor Pipeline”), which operates our water supply and salt water disposal systems in our primary development area, and Endeavor Gathering, LLC (“Endeavor Gathering”), which owns the natural gas gathering system and related equipment operated by Endeavor Pipeline. Kinder Morgan Endeavor LLC (“KME”) owns 40% membership interest in Endeavor Gathering.

Basis of Presentation

The accompanying unaudited consolidated financial statements and condensed notes thereto of GMX 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 GMX’s 2010 Annual Report on Form 10-K (“2010 10-K”).

In the opinion of GMX’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 GMX as of September 30, 2011, and the results of its operations for the three and nine months ended September 30, 2011 and 2010 and its cash flow for the nine months ended September 30, 2011 and 2010.

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. Because the Company was in a loss position for the three and nine months ended September 30, 2011, the instruments mentioned above would decrease diluted loss per share, which would result in antidilutive instruments. Therefore, there were no dilutive shares for the three and nine months ended September 30, 2011. There were 11,097 and 68,754 dilutive shares related to the Company's stock options and non-vested restricted stock awards as of the three and nine months ended September 30, 2010, respectively.

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 $4.1 million as of both September 30, 2011 and December 31, 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 cost of unproved properties is added to the future net revenues less income tax effects. At September 30, 2011 and 2010, 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 prices for the prior 12-month period for natural gas and oil as of September 30, 2011, these cash flow hedges increased the full-cost ceiling by $33.9 million, thereby reducing the ceiling test write-down by the same amount. Excluding the effects of cash flow hedges, which increased the full cost ceiling by $58.6 million, we would have incurred a ceiling test write-down of $37.3 million for the nine months ended September 30, 2010.

The primary factors impacting the full cost method ceiling test are expenditures added to the full cost pool, reserve levels, value of cash flow hedges 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 is generally written off as an expense. Natural gas represents 90% of the Company’s total production, and as a result, a decrease in natural gas prices can significantly impact the Company’s ceiling test. During the first nine months of 2011, the 12-month average of the first day of the month natural gas price decreased 5% from $4.38 per MMbtu at December 31, 2010 to $4.16 per MMbtu at September 30, 2011. As a result of the Company’s quarterly ceiling test, the Company recorded impairment expense related to oil and gas properties of $120.4 million through the first nine months of 2011.

For the oil and gas impairment charge recorded in the first nine months of 2011, $14.5 million of the $127.3 million charge was related to the acquisition cost of undeveloped acreage subject to the impairment test, based on the Company’s decision during the first quarter of 2011 not to develop the acreage before the expiration of the related leases. The Company’s decision not to develop the acreage was based on analysis completed in the first quarter of 2011, after looking at off-set wells, anticipated future gas prices, infrastructure costs, the Company’s liquidity position and focus on exploration and development of the newly acquired acreage in Bakken and Niobrara areas.

Assets held for sale on our consolidated balance sheets are measured at the lesser of carrying value or fair value less cost to sell. Based on offers received during the quarter to purchase a portion of our assets held for sale for a lower amount than the carrying amount, we estimated that those assets should further be impaired by approximately $7.3 million for the nine months ended September 30, 2011. As a result of recording this additional impairment on assets held for sale, the Company's total impairment recorded for the nine months ended September 30, 2011, related to assets sold and assets held for sale totaled $7.3 million. Total impairments for the nine months ended September 30, 2011, including impairments on oil and gas properties and assets held for sale is $127.7 million.

Recent Accounting Standards

In January 2010, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2010-06, “Improving Disclosures about Fair Value Measurements” (“ASU No. 2010-06”), a standard intended to improve disclosures about fair value measurements. 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 ASU No. 2010-06 effective as of the first quarter of 2010. The adoption had no impact on our consolidated financial position or results of operations.