UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

______________________________________ 

FORM 10-Q

______________________________________ 

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2012

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from  to

Commission File Number 001-32977

______________________________________ 

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  o

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  x    No  o

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:

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

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

The number of shares outstanding of the registrant’s common stock as of August 8, 2012 was 75,533,632, which included 2,364,375 shares under a share loan which will be returned to the registrant upon conversion of certain outstanding convertible notes.

GMX Resources Inc.

Form 10-Q

For the Quarter Ended June 30, 2012

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION		3
ITEM 1.	Financial Statements	3
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operation.	24
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	36
ITEM 4.	Controls and Procedures	37
PART II. OTHER INFORMATION		39
ITEM 1.	Legal Proceedings	39
ITEM 1A.	Risk Factors	39
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
ITEM 6.	Exhibits	41
SIGNATURES		42

2

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

GMX Resources Inc. and Subsidiaries

Consolidated Balance Sheets

	June 30, 2012			December 31, 2011
ASSETS	(Unaudited)
CURRENT ASSETS:	(In thousands, except share data)
Cash and cash equivalents	$	32,122		$	102,493
Restricted cash	4,325			4,325
Short-term investments	6,008			—
Accounts receivable – interest owners	5,952			8,607
Accounts receivable – oil and natural gas revenues, net	4,705			7,082
Derivative instruments	1,929			—
Inventories	326			326
Prepaid expenses and deposits	1,583			2,655
Assets held for sale	410			2,045
Total current assets	57,360			127,533
OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD
Properties being amortized	1,105,167			1,062,801
Properties not subject to amortization	162,783			147,224
Less accumulated depreciation, depletion, and impairment	(1,003,510		)	(871,346		)
	264,440			338,679
PROPERTY AND EQUIPMENT, AT COST, NET	63,159			65,858
DERIVATIVE INSTRUMENTS	1,451			—
OTHER ASSETS	8,382			10,131
TOTAL ASSETS	$	394,792		$	542,201
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	11,582		$	13,550
Accrued expenses	15,911			17,835
Accrued interest	4,956			3,256
Revenue distributions payable	5,609			5,980
Short-term derivative instruments	1,141			—
Current maturities of long-term debt	51,256			26
Total current liabilities	90,455			40,647
LONG-TERM DEBT, LESS CURRENT MATURITIES	362,987			426,805
DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS	608			—
OTHER LIABILITIES	8,415			7,476
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, 6,000,000 shares authorized, 3,176,734 shares issued and outstanding as of June 30, 2012 and December 31, 2011 (aggregate liquidation preference $79,418 as of June 30, 2012 and December 31, 2011)	3			3
Common stock, par value $.001 per share – 250,000,000 shares authorized, 74,451,790 shares issued and outstanding as of June 30, 2012 and 63,085,432 shares issued and outstanding as of December 31, 2011	74			63
Additional paid-in capital	709,829			690,986
Accumulated deficit	(796,073		)	(649,341		)
Accumulated other comprehensive income, net of taxes	7,764			14,029
Total GMX Resources’ equity	(78,403		)	55,740
Noncontrolling interest	10,730			11,533
Total equity	(67,673		)	67,273
TOTAL LIABILITIES AND EQUITY	$	394,792		$	542,201

See accompanying notes to consolidated financial statements.

3

GMX Resources Inc. and Subsidiaries

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
	(In thousands, except share and per share data)
OIL AND GAS SALES	$	16,283		$	32,858		$	33,684		$	62,235
EXPENSES:
Lease operations	2,888			2,836			5,996			5,733
Production and severance taxes	556			166			319			549
Depreciation, depletion, and amortization	6,974			13,304			14,439			26,093
Impairment of oil and natural gas properties and assets held for sale	91,690			16,861			120,690			65,181
General and administrative	6,802			7,605			13,797			14,683
Total expenses	108,910			40,772			155,241			112,239
Loss from operations	(92,627		)	(7,914		)	(121,557		)	(50,004		)
NON-OPERATING INCOME (EXPENSES):
Interest expense	(10,122		)	(7,832		)	(20,825		)	(15,854		)
Gain (loss) on conversion/extinguishment of debt	831			(67		)	3,612			(176		)
Interest and other income	35			12			108			282
Unrealized gain (loss) on derivatives	(11		)	5,437			779			4,992
Total non-operating expense	(9,267		)	(2,450		)	(16,326		)	(10,756		)
Loss before income taxes	(101,894		)	(10,364		)	(137,883		)	(60,760		)
INCOME TAX PROVISION	(1,418		)	(1,436		)	(3,305		)	(2,868		)
NET LOSS	(103,312		)	(11,800		)	(141,188		)	(63,628		)
Net income attributable to noncontrolling interest	982			1,746			1,870			3,158
NET LOSS APPLICABLE TO GMX RESOURCES	(104,294		)	(13,546		)	(143,058		)	(66,786		)
Preferred stock dividends	1,837			1,837			3,673			3,047
NET LOSS APPLICABLE TO COMMON SHAREHOLDERS	$	(106,131	)	$	(15,383	)	$	(146,731	)	$	(69,833	)
LOSS PER SHARE – Basic	$	(1.52	)	$	(0.28	)	$	(2.23	)	$	(1.43	)
LOSS PER SHARE – Diluted	$	(1.52	)	$	(0.28	)	$	(2.23	)	$	(1.43	)
WEIGHTED AVERAGE COMMON SHARES – Basic	69,925,895			55,660,978			65,832,321			48,959,825
WEIGHTED AVERAGE COMMON SHARES – Diluted	69,925,895			55,660,978			65,832,321			48,959,825

See accompanying notes to consolidated financial statements.

4

GMX Resources Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
	(In thousands)
Net loss	$	(103,312	)	$	(11,800	)	$	(141,188	)	$	(63,628	)
Other comprehensive loss, net of income tax:
Change in fair value of derivative instruments, net of income tax of $0, ($79), $0 and $2, respectively	—			(153		)	—			3
Reclassification of gain on settled contracts, net of income taxes of ($1,418), ($1,357), ($3,227) and ($2,868), respectively	(2,753		)	(2,634		)	(6,265		)	(5,568		)
Comprehensive loss	(106,065		)	(14,587		)	(147,453		)	(69,193		)
Comprehensive income attributable to the noncontrolling interest	982			1,746			1,870			3,158
Comprehensive loss attributable to GMX shareholders	$	(107,047	)	$	(16,333	)	$	(149,323	)	$	(72,351	)

See accompanying notes to consolidated financial statements.

5

GMX Resources Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended
	June 30,
	2012			2011
CASH FLOWS DUE TO OPERATING ACTIVITIES	(In thousands)
Net loss	$	(141,188	)	$	(63,628	)
Depreciation, depletion, and amortization	14,439			26,093
Impairment of oil and natural gas properties and assets held for sale	120,690			65,181
Deferred income taxes	3,305			2,867
Non-cash compensation expense	2,292			2,155
(Gain) loss on conversion/extinguishment of debt	(3,612		)	176
Non-cash interest expense	4,163			4,622
Non-cash change in fair value of derivative financial instruments	(779		)	(4,992		)
Non-cash derivative gain in oil and gas sales	(9,493		)	—
Other	(28		)	(722		)
Decrease (increase) in:
Accounts receivable	4,856			(634		)
Inventory and prepaid expenses	1,166			(231		)
Increase (decrease) in:
Accounts payable and accrued liabilities	(3,515		)	5,474
Revenue distributions payable	(358		)	1,263
Net cash (used in) provided by operating activities	(8,062		)	37,624
CASH FLOWS DUE TO INVESTING ACTIVITIES
Purchase, exploration and development of oil and natural gas properties	(52,974		)	(192,708		)
Proceeds from sale of oil and natural gas properties, property, equipment and assets held for sale	1,765			2,189
Purchase of short term investments	(6,029		)	—
Purchase of property and equipment	(418		)	(1,739		)
Net cash used in investing activities	(57,656		)	(192,258		)
CASH FLOWS DUE TO FINANCING ACTIVITIES
Borrowings on revolving bank credit facility	—			26,000
Repayments of long-term debt	(24		)	(168,035		)
Proceeds from issuance of long-term debt	—			193,666
Proceeds from sale of common stock	—			105,324
Proceeds from sale of preferred stock	—			25,809
Dividends paid on Series B preferred stock	(1,837		)	(3,047		)
Fees paid related to financing activities	(118		)	(16,132		)
Contributions from non-controlling interest member	—			385
Distributions to non-controlling interest member	(2,674		)	(6,816		)
Net cash (used in) provided by financing activities	(4,653		)	157,154
NET (DECREASE) INCREASE IN CASH	(70,371		)	2,520
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	102,493			2,357
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	32,122		$	4,877
SUPPLEMENTAL CASH FLOW DISCLOSURE
CASH PAID DURING THE PERIOD FOR:
INTEREST, Net of amounts capitalized	$	11,531		$	3,336
INCOME TAXES, Paid	$	24		$	1
NON-CASH INVESTING AND FINANCING ACTIVITIES
Debt extinguished with common stock	$	20,753		$	—
Additions to oil and natural gas properties in exchange for common stock	$	—		$	31,612
Decrease in accounts payable for property additions	$	4,451		$	7,079
Interest paid in the form of additional notes ("PIK Election")	$	5,102		$	—

See accompanying notes to consolidated financial statements.

6

GMX Resources Inc. and Subsidiaries

Condensed Notes to the Consolidated Interim Financial Statements

(Unaudited)

NOTE A – 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 with a portfolio of leasehold acreage in multiple resource plays that allows the Company flexibility to deploy capital based on a variety of economic and technical factors, including commodity prices (including differentials applicable to the basin), well costs, service availability, and take-away capacity.

Prior to 2011, the Company focused on the development of the hydrocarbon formations in East Texas including the Cotton Valley Sands (“CVS”) layer in the Schuler formation and the Upper, Middle and Haynesville/Lower Bossier layers of the Bossier formation (“H/B”), in the Sabine Uplift of the Carthage, North Field primarily located in Harrison and Panola counties of East Texas (previously designated as our “primary development area”).

In late 2010, we made a strategic decision to expand our asset base and development activities into other basins in order to diversify our significant concentration in natural gas to a multiple basin and commodity strategy with more liquid hydrocarbon opportunities. In the first half of 2011, we acquired core positions in over 75,000 undeveloped net acres in two of the leading oil resource plays in the U.S.: the Williston Basin of North Dakota/Montana, targeting the Bakken/ Three Forks Formation; and in the oil window of the Denver Julesburg Basin (the “DJ Basin”) of Wyoming, targeting the emerging Niobrara Formation. We believe the oil production from the liquids-rich (estimated 90% oil) Bakken and Niobrara acreage will enable us to generate higher cash flow growth to fund our capital expenditure program. The Company is utilizing our expertise in H/B shale horizontal drilling to explore and develop these oil resources.

We have three subsidiaries: Diamond Blue Drilling Co. (“Diamond Blue”), which sold its assets in 2011 and is not active, Endeavor Pipeline Inc. (“Endeavor Pipeline”), which operates our water supply and salt water disposal systems in our East Texas 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 a 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 2011 Annual Report on Form 10-K (“2011 Form 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 June 30, 2012, and the results of its operations and cash flows for the three and six months ended June 30, 2012 and 2011.

Liquidity and Management's Plans

At June 30, 2012, the Company had a working capital deficit of $33.1 million, which included $51.2 million in current liabilities related to the 5.00% Convertible Notes due February 2013 ("5.00% Convertible Notes") and cash, restricted cash and short-term investments of $42.5 million in current assets.

The Company has successfully reduced the original principal amount of the 5.00% Convertible Notes by $73 million and is undertaking multiple steps to address the remaining $52 million principal balance. The Company continues to evaluate potential debt-for-equity exchanges with holders of the 5.00% Convertible Notes, as well as evaluating a potential debt-for-debt exchange. The Company is also focused on increasing its liquidity to fund the on-going Bakken oil drilling program.

In July 2012, the Company engaged a financial advisor in connection with a proposed sale of a portion of the Company's Cotton Valley Sand liquids rich natural gas properties located in East Texas. The Proved Developed and Producing wells are in the mature stage of production with shallow decline rates. The assets being sold have additional upside through infill horizontal development on acreage that is all held by production. The Company currently expects the sale of these properties to occur during the third quarter of 2012, with the proceeds to be used for our Bakken drilling program. We are also analyzing

7

our seismic program in the Niobrara which may facilitate a partial sale or joint venture on our 40,000 acres, potentially increasing the Company's liquidity position for more oil development. In addition to asset sales and continued execution of our business plan, the Company has relied on the capital markets to fund the acceleration of its drilling programs. Management believes that these actions will enable the Company to meet its liquidity requirements through the next twelve months.

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 six months ended June 30, 2012 and 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 six months ended June 30, 2012 and 2011.

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 $3.6 million as of June 30, 2012 and $3.8 million as of December 31, 2011, 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. Future net revenues are calculated using prices that represent the average of the first day of the month price for the 12-months ending at 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.

The primary factors impacting the full cost method ceiling test are expenditures added to the full cost pool, reserve levels, 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 79% of the Company’s total production for the three months ended June 30, 2012, and as a result, a decrease in natural gas prices can significantly impact the Company’s ceiling test. During the first six months of 2012, the 12-month average of the first day of the month natural gas price decreased 24% from $4.12 per million British thermal units (MMbtu) at December 31, 2011 to $3.15 per MMbtu at June 30, 2012. As a result of the Company’s quarterly ceiling test, the Company recorded impairment expense related to oil and gas properties of $91.8 million and $120.8 million for the three and six months endedJune 30, 2012, respectively.

Assets held for sale are carried on the balance sheet at their carrying value or fair value less cost to sell, whichever is less. Subsequent increases in fair value less cost to sell will be recognized as a gain, but not in excess of the cumulative loss previously recognized. In April 2012, the Company sold a compressor, which was included in assets held for sale as of March 31, 2012, for $1.5 million and a gain of $0.1 million was recognized on that sale. The remaining assets held for sale of $0.4 million as of June 30, 2012 consist of valves and pipe, which the Company is actively marketing.

Recent Accounting Standards

In June 2011, the FASB issued ASU No. 2011-05, Presentation of Comprehensive Income. The issuance of ASU 2011-5 is intended to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The guidance in ASU 2011-5 supersedes the presentation options in ASC Topic 220 and facilitates convergence of U.S. generally accepted accounting principles and International Financial Reporting Standards ("IFRS") by eliminating the option to present components of other comprehensive income as part of the statement of changes in shareholders' equity and requiring that all non-owner changes in shareholders' equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This guidance is effective during the interim and annual periods beginning after December 15, 2011. The adoption of this guidance did not have a material

8

impact on the Company’s consolidated financial statements.

In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S GAAP and IFRS. This amendment of the FASB Accounting Standards Codification is to ensure that fair value has the same meaning in U.S. GAAP and IFRS and that their respective fair value measurement and disclosure requirements are the same. This guidance is effective during the interim and annual periods beginning after December 15, 2011. The adoption of the guidance did not have any material effect on the Company’s financial statements.

NOTE B – LONG-TERM DEBT

The table below presents the carrying amounts and approximate fair values of our debt obligations. The approximate fair values of our convertible and other debt securities are determined based on market quotes from independent third party brokers as they are actively traded in an established market.

	June 30, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
			(in thousands)
5.00% Convertible Senior Notes due February 2013	$	51,230	$	41,598	$	70,757	$	46,560
4.50% Convertible Senior Notes due May 2015	78,634		38,813		77,457		41,400
11.375% Senior Notes due February 2019	1,915		1,290		1,912		1,300
Senior Secured Notes due December 2017	281,194		236,056		275,411		283,475
Joint venture financing(1)	1,270		1,270		1,294		1,294
Total	$	414,243	$	319,027	$	426,831	$	374,029

 __________________

(1) Non-recourse, no interest rate

5.00% Convertible Senior Notes

As of June 30, 2012 and December 31, 2011, the net carrying amount of our 5.00% Convertible Senior Notes (the "5.00% Convertible Notes") was as follows (amounts in thousands):

	June 30, 2012			December 31, 2011
Principal amount	$	51,997		$	72,750
Less: Unamortized debt discount	(767		)	(1,993		)
Carrying amount	$	51,230		$	70,757

The 5.00% Convertible Notes bear interest at a rate of 5.00% per year, payable semi-annually 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 7.68% per annum. The amount of the cash interest expense recognized with respect to the 5.00% contractual interest coupon for the three and six months ended June 30, 2012 was $0.7 million and $1.6 million, respectively, and $0.9 million and $2.3 million for the three and six months ended June 30, 2011, respectively. The amount of non-cash interest expense related to the amortization of the debt discount and amortization of the transaction costs for the three and six months ended June 30, 2012 was $0.4 million and $1.0 million, respectively, and $0.4 million and $1.1 million for the three and six months ended June 30, 2011, respectively.

As of June 30, 2012, the unamortized debt discount is expected to be amortized into earnings over 0.6 years. The carrying value of the equity component of the 5.00% Convertible Notes was $3.9 million as of June 30, 2012. As of June 30, 2012 and December 31, 2011, unamortized debt issue costs were approximately $0.2 million and $0.6 million, respectively, with all costs included in prepaid expenses and deposits and other assets, respectively, to reflect the current and long-term amortization periods consistent with the current and long-term classification of the related 5.00% Convertible Notes.

As of June 30, 2012, the balance of the 5.00% Convertible Notes was classified as a current liability due to the maturity date of February 1, 2013. During 2012, we entered into separate exchange agreements with various holders of our 5.00% Convertible Notes. Pursuant to these agreements, as consideration for the surrender by the holders of $20.8 million aggregate principal amount of the 5.00% Convertible Notes, we issued to the holders an aggregate of 11,271,510 shares of our common stock. As a result, the Company has recorded a net gain of approximately $3.8 million, including a loss of approximately $15.4

9

million for the early conversion offer and a gain of approximately $19.2 million for the cancellation of indebtedness of such 5.00% Convertible Notes. We continue to evaluate additional options for refinancing and/or repayment of these notes prior to their maturity in February 2013. See discussion of these options in Note A - Nature of Operations and Summary of Significant Accounting Policies.

4.50% Convertible Senior Notes

As of June 30, 2012 and December 31, 2011, the net carrying amount of our 4.50% Convertible Senior Notes due 2015 (the "4.50% Convertible Notes") was as follows (amounts in thousands):

	June 30, 2012			December 31, 2011
Principal amount	$	86,250		$	86,250
Less: Unamortized debt discount	(7,616		)	(8,793		)
Carrying amount	$	78,634		$	77,457

The 4.50% Convertible Notes bear interest at a rate of 4.50% per year, payable semiannually in arrears on November 1 and May 1 of each year, beginning May 1, 2010. As a result of the amortization of the debt discount through non-cash interest expense, the effective interest rate on the 4.50% Convertible Notes is 9.09% per annum. The amount of the cash interest expense recognized with respect to the 4.50% contractual interest coupon for the three and six months ended June 30, 2012 was $1.0 million and $1.9 million, respectively, and $1.0 million and $1.9 million for the three and six months ended June 30, 2011, respectively. The amount of non-cash interest expense related to the amortization of the debt discount and transaction costs for the three and six months ended June 30, 2012 was $0.7 million and $1.5 million, respectively, and $0.6 million and $1.1 million for the three and six months ended June 30, 2011, respectively. As of June 30, 2012, the unamortized discount is expected to be amortized into earnings over 2.8 years. The carrying value of the equity component of the 4.50% Convertible Notes was $8.4 million as of June 30, 2012.

11.375% Senior Notes

On February 9, 2011, the Company successfully completed the issuance and sale of $200 million aggregate principal amount of 11.375% Senior Notes due 2019 (the “11.375% Senior Notes”). The 11.375% Senior Notes are jointly and severally, and unconditionally, guaranteed (the “guarantees”) on a senior unsecured basis initially by two of our wholly-owned subsidiaries, and all of our future subsidiaries other than immaterial subsidiaries (such guarantors, the “Guarantors”). The 11.375% senior notes and the guarantees were issued pursuant to an indenture dated as of February 9, 2011 (the “Indenture”), by and among the Company, the Guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., a national banking association, as trustee (the “Trustee”).

In December 2011, the Company entered into an exchange transaction related to the new Senior Secured Notes mentioned below. Approximately $198 million of the 11.375% Senior Notes were exchanged to new Senior Secured Notes. As of June 30, 2012 and December 31, 2011, the net carrying amount of the 11.375% Senior Notes was as follows (amounts in thousands):

	June 30, 2012			December 31, 2011
Principal amount	$	1,970		$	1,970
Less: Unamortized debt discount	(55		)	(58		)
Carrying amount	$	1,915		$	1,912

The11.375% senior notes bear interest at a rate of 11.375% per year, payable semi-annually in arrears on February 15 and August 15 of each year, beginning August 15, 2011. As a result of the amortization of the debt discount through non-cash interest expense, the effective interest rate on the 11.375% senior notes is 12.94% per annum. The amount of the cash interest expense recognized with respect to the 11.375% contractual interest coupon for the three and six months ended June 30, 2012 was $56,000 and $112,000, respectively, and $5.7 million and $9.0 million for the three and six months ended June 30, 2011, respectively. The amount of non-cash interest expense related to the amortization of the debt discount and transaction costs for the three and six months ended June 30, 2012 was $2,700 and $5,000, respectively, and $0.4 million and $0.6 million for the three and six months ended June 30, 2011, respectively. As of June 30, 2012, the unamortized discount is expected to be amortized into earnings over 6.6 years.

Material covenants were removed as part of the exchange offer and issuance of the Senior Secured Notes during December 2011.

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Senior Secured Notes

On December 19, 2011, the Company executed an indenture (the “Senior Secured Notes Indenture”), among the Company, the guarantors party thereto and U.S. Bank National Association, as trustee. The Company issued $283,475,000 aggregate principal amount of Senior Secured Notes due 2017 (the “Senior Secured Notes”) pursuant to the Senior Secured Notes Indenture. The Senior Secured Notes are fully and unconditionally guaranteed (the “Guarantees”), jointly and severally, on a senior secured basis by each of the Company’s existing and future domestic restricted subsidiaries (the “Guarantors”). All of the Company’s existing subsidiaries other than Endeavor Gathering, LLC are domestic restricted subsidiaries and Guarantors. As of June 30, 2012 and December 31, 2011, the net carrying amount of the Senior Secured Notes was as follows (amounts in thousands):

	June 30, 2012			December 31, 2011
Principal amount	$	288,577		$	283,475
Less: Unamortized debt discount	(7,383		)	(8,064		)
Carrying amount	$	281,194		$	275,411

The Senior Secured Notes bear interest at a rate of 11.00% per year, payable semiannually on June 1 and December 1 of each year, beginning June 1, 2012. The Indenture for the Senior Secured Notes provide the Company the option to pay a portion of the interest due in the form of additional notes ("PIK Election"), which allows for a 9.00% cash interest payment along with additional Senior Secured Notes of 4.00% resulting in an annual interest rate of 13.00%. For the June 1, 2012 interest payment, the Company elected the PIK Election and paid cash interest of $11.5 million and issued an additional $5.1 million of Senior Secured Notes. As a result of the amortization of the debt discount through non-cash interest expense, the effective interest rate on the Senior Secured Notes is 11.68% per annum if the cash only option is elected. If the PIK option is elected, the effective interest rate on the Senior Secured Notes is 13.52% per annum. The amount of the interest expense recognized with respect to the 13.00% PIK Election interest coupon for the three and six months ended June 30, 2012 was $9.3 million and $18.7 million, respectively. The amount of non-cash interest expense for the three and six months ended June 30, 2012 related to the amortization of the debt discount and transaction costs was $0.3 million and $0.5 million, respectively. As of June 30, 2012, the unamortized discount is expected to be amortized into earnings over 5.4 years.

NOTE C – 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 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 price of 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 utilizes counterparties 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.

None of the Company’s derivative instruments contain credit-risk-related contingent features. Additionally, 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.

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As a result of hedging transactions entered into in the first half of 2012, the Company recorded a net derivative asset. This net derivative asset is being accounted for at fair value with the changes in fair value recorded to the consolidated statement of operations.

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

		Asset Fair Value				Liability Fair Value				Net Derivative Fair Value
	Balance Sheet Location	June 30, 2012		December 31, 2011		June 30, 2012		December 31, 2011		June 30, 2012			December 31, 2011
		(in thousands)				(in thousands)				(in thousands)
Derivatives not designated as Hedging Instruments under ASC 815
Natural gas	Current derivative liability	$	—	$	—	$	1,141	$	—	$	(1,141	)	$	—
Crude oil	Current derivative asset	1,929		—		—		—		1,929			—
Natural gas	Other liabilities – non-current	—		—		453		—		(453		)	—
Crude oil	Derivative instruments – non-current asset	1,451		—		—		—		1,451			—
		$	3,380	$	—	$	1,594	$	—	$	1,786		$	—

The following table summarizes the outstanding natural gas and crude oil derivative contracts the Company had in place as of June 30, 2012:

Effective Date	Maturity Date	Notional Amount Per Month	Remaining Notional Amount as of June 30, 2012	Additional Put Options	Floor	Ceiling	Designation under ASC 815
Natural Gas (MMBtu):
7/1/2012	12/31/2012	429,113	2,574,680		$2.60	$2.60	Not designated
7/1/2012	12/31/2012	97,184	583,104		$2.50	$3.20	Not designated
1/1/2013	12/31/2013	353,559	4,242,710		$3.50	$3.50	Not designated
1/1/2013	12/31/2013	82,240	986,876	$3.00	$3.68	$3.68	Not designated
Crude Oil (Bbls):
7/1/2012	12/31/2012	5,060	30,360		$96.50	$96.50	Not designated
7/1/2012	12/31/2012	3,237	19,421	$90.00	$100.00		Not designated
7/1/2012	12/31/2013	3,749	67,489		$106.40	$106.40	Not designated
1/1/2013	12/31/2013	3,498	41,975	$65.50	$106.40		Not designated
1/1/2013	12/31/2013	3,194	38,325	$70.00	$90.00		Not designated
1/1/2013	12/31/2013	2,221	26,654		$100.00		Not designated
1/1/2014	12/31/2014	2,961	35,528	$80.00	$100.00	$114.10	Not designated
1/1/2014	12/31/2014	1,658	19,893	$75.00	$95.00		Not designated
1/1/2014	12/31/2014	3,042	36,500	$70.00	$90.00		Not designated

All of the above natural gas contracts are settled against NYMEX, and all oil contracts are settled against NYMEX Light Sweet Crude. The NYMEX and NYMEX Light Sweet Crude have historically had a high degree of correlation with the actual prices received by the Company. In connection with our natural gas swaps, we also entered into a Basis Swap in which we locked in a natural gas price at the Houston Ship Channel at a $0.08/MMbtu discount to NYMEX. The combination of these

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trades effectively locks in a sales price to GMXR of $2.52 for 2.57 BCF during the last 6 months of 2012, and $3.42 for 4.24 BCF during 2013.

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 ("OCI") 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.

In December 2011, the Company settled its entire hedge portfolio. Under ASC 815-30-40, the Company is required to recognize the balance of the cumulative gain, recorded in accumulated other comprehensive income in the previous periods, over the life of the remaining contractual life of the original hedged transaction. For the three and six months ended June 30, 2012, the Company recognized $4.2 million and $9.5 million, respectively, of the cumulative gain in oil and gas sales on the consolidated statement of operations. As of June 30, 2012, the balance of the Company's cumulative gain, net of taxes, recorded in accumulated other comprehensive income was $7.8 million, of which $4.8 million will be recognized into earnings through December 31, 2012, with the remainder recognized in 2013.

There were no oil or gas derivatives classified as hedges for the three and six months ended June 30, 2012. A summary of the effect of the natural gas derivatives qualifying for hedges for the three and six months ended June 30, 2011 is as follows:

		Natural Gas Derivatives Qualifying as Hedges
	Location of Amounts	Three Months Ended June 30, 2011
		(in thousands)
Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	OCI	(232	)
Amount of Gain Reclassified from Accumulated OCI into Income (Effective Portion)	Oil and Gas Sales	3,991
Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Oil and Gas Sales	315

		Natural Gas Derivatives Qualifying as Hedges
	Location of Amounts	Six Months Ended June 30, 2011
		(in thousands)
Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	OCI	5
Amount of Gain Reclassified from Accumulated OCI into Income (Effective Portion)	Oil and Gas Sales	8,436
Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Oil and Gas Sales	722

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:

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	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
		Three Months Ended June 30,
		2012			2011
		(in thousands)
Realized
Natural gas	Oil and gas sales	$	509		$	—
Crude oil	Oil and gas sales	244			(44		)
Unrealized
Natural gas	Unrealized gain or (loss)on derivatives	(2,107		)	5,110
Crude oil	Unrealized gain or (loss)on derivatives	2,096			327
		$	742		$	5,393

	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
		Six Months Ended June 30,
		2012			2011
		(in thousands)
Realized
Natural gas	Oil and gas sales	$	509		$	—
Crude oil	Oil and gas sales	244			(44		)
Unrealized
Natural gas	Unrealized gain or (loss)on derivatives	(1,594		)	5,110
Crude oil	Unrealized gain or (loss)on derivatives	2,373			(118		)
		$	1,532		$	4,948

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 June 30, 2012 and December 31, 2011:

	As of June 30, 2012							As of December 31, 2011
	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	$	—	$	(1,594	)	$	—	$	—	$	—	$	—
Crude oil derivative instruments	$	—	$	3,380		$	—	$	—	$	—	$	—

NOTE D – STOCK COMPENSATION PLANS

We recognized $1.6 million and $1.2 million of stock compensation expense for the three months ended June 30, 2012 and 2011, respectively, and $2.5 million and $2.4 million for the six months ended June 30, 2012 and 2011, respectively. These non-cash expenses are reflected as a component of the Company’s general and administrative expense. To the extent recognized compensation costs relates to employees directly involved in exploration and development activities, such amounts are

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capitalized to oil and natural gas properties. Stock based compensation capitalized as part of oil and natural gas properties was $0.1 million and $0.1 million for the three months ended June 30, 2012 and 2011, respectively, and $0.2 million and $0.3 million for the six months ended June 30, 2012 and 2011, respectively.

Restricted Stock

A summary of the status of our unvested shares of restricted stock and the changes for the year ended December 31, 2011 and the six months ended June 30, 2012 is presented below:

	Number of unvested restricted shares		Weighted average  grant- date fair value per share
Unvested shares as of December 31, 2010	691,996		$	13.47
Granted	807,848		$	4.79
Vested	(245,924	)	$	16.46
Forfeited	(5,521	)	$	19.42
Unvested shares as of December 31, 2011	1,248,399		$	7.24
Vested	(104,761	)	$	17.53
Forfeited	(8,371	)	$	9.28
Unvested shares as of June 30, 2012	1,135,267		$	6.28

In March 2012, the vesting period of the restricted shares issued to the executives and members of the Board of Directors on August 2, 2011 were accelerated to an earlier date. There were no incremental compensation costs calculated as a result of the modification. Unamortized compensation costs were accelerated to earlier future periods consistent with the new vesting schedule of the restricted shares.

As of June 30, 2012, there was $4.6 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 1.2 years.

NOTE E – CAPITAL STOCK

Share Lending Arrangement

In February 2008, in connection with the offer and sale of the 5.00% Convertible Notes, we entered into a share lending agreement (the “Share Lending Agreement”). Under this agreement, we loaned to the share borrower up to the maximum number of shares of our common stock underlying the 5.00% Convertible Notes. As of June 30, 2012 there were 2,364,375 shares of our outstanding common stock subject to loans to the share borrower under the Share Lending Agreement.

Issuance of Common Stock

During the six months ended June 30, 2012, the Company converted $20.8 million aggregate principal amount of its 5.00% Convertible Notes due 2013 to 11,271,510 shares of common stock. See Note B, Long-Term Debt.

NOTE F – INCOME TAXES

We recorded tax provisions of $1.4 million and $1.4 million for the three months ended June 30, 2012 and 2011, respectively, and $3.3 million and $2.9 million for the six months ended June 30, 2012 and 2011, 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 June 30, 2012 and December 31, 2011.  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.

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NOTE G – COMMITMENTS AND CONTINGENCIES

Litigation

A putative class action lawsuit was filed by the Northumberland County Retirement System and Oklahoma Law Enforcement Retirement System (collectively, the “Nothumberland Plaintiffs”)in the District Court in Oklahoma County, Oklahoma, purportedly on March 10, 2011, against the Company and certain of its officers along with certain underwriters of the Company's July 2008, May 2009 and October 2009 public offerings. Discovery requests and summons were filed and issued in late April 2011. The complaint alleges that the registration statement and the prospectus for contained material misstatements and omissions and seeks damages under Sections 11, 12 and 15 of the Securities Act of 1933 of an unspecified equitable relief. Defendants removed the case to federal court on May 12, 2011 and filed motions to dismiss on June 20, 2011. Plaintiffs filed a motion to remand the case to state court on June 10, 2011, and Defendants filed an opposition to that motion. By order dated November 16, 2011, the court denied Plaintiffs' motion to remand. On February 3, 2012, Plaintiffs moved to be appointed lead plaintiff under the Private Securities Litigation Reform Act. By order dated July 3, 2012, the Court appointed the Northumberland Plaintiffs lead plaintiff. By August 16, 2012, Plaintiffs are expected to elect to move forward with their existing complaint or to file an amended complaint, with Defendants' responses thereto expected to be filed later in 2012. We are currently unable to assess the probability of loss or estimate a range of potential loss, if any, associated with the securities class action case, which is at an early stage.

On August 5, 2011, an individual filed a shareholders' derivative action in the United States District Court for the Western District of Oklahoma, for the Company's benefit, as nominal defendant, against the Company's Chief Executive Officer, President, Chief Financial Officer, and certain members of the Company's board of directors. The complaint alleges breaches of fiduciary duty, waste of corporate assets, and unjust enrichment on the part of each of the named defendants and is premised on substantially the same facts alleged in the above-described securities lawsuit. The complaint seeks unspecified amounts of compensatory damages, implementation of certain corporate governance changes, and disgorgement of compensation and trading profits from the individual defendants, as well as interest and costs, including legal fees from the defendants. The Company is a nominal defendant, and the complaint does not seek any damages against the Company; however, the Company may have indemnification obligations to one or more of the defendants under the Company's organizational documents. On October 17, 2011, the individual defendants and the Company as nominal defendant filed motions to dismiss the complaint for failure to make demand, or in the alternative, to stay the derivative action pending the outcome of the securities lawsuit. The case is currently stayed pending the outcome of the motions to dismiss that are expected to be filed with respect to the securities lawsuit described above. On March 23, 2012, an additional plaintiff filed a similar derivative action in the United States District Court for the Western District of Oklahoma. The parties agreed to consolidate this case with the existing federal court derivative action. The federal court derivative actions have been consolidated, and the cases are stayed pending the outcome of the motions to dismiss the securities lawsuit described above. We are currently unable to assess the probability of loss or estimate a range of potential loss, if any, associated with this case.

On February 7 and 9, 2012, two individuals filed separate shareholder derivative actions in the District Court of Oklahoma County, in the State of Oklahoma, for the Company's benefit, as nominal defendant, against the Company's Chief Executive Officer, President, Chief Financial Officer, and each member of the Company's board of directors. The petitions assert claims and seek relief similar to those asserted and sought in the federal court derivative action described above. Plaintiffs filed a motion to consolidate the two state court derivative actions, and the court consolidated the two actions. The parties have agreed that plaintiffs will file an amended and consolidated petition after the plaintiffs in the federal securities action described above file their amended complaint. On April 9, 2012, defendants filed a motion to dismiss, a motion to stay, and a motion for protection from discovery. By stipulation dated May 29, 2012, the parties agreed to stay these cases pending the outcome of the motions to dismiss the securities lawsuit described above and to stay discovery. We are currently unable to assess the probability of loss or estimate a range of potential loss, if any, associated with this case.

The Company is party to various legal actions arising in the normal course of business. Matters that are probable to have an 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.

Insurance Matters

The Company maintains property damage, business interruption and other insurance coverage, the scope and amounts of which we believe are customary and prudent for the nature and extent of our operations. The Company also believes its deductibles are consistent with customary and prudent industry practices and does not expect that the payment of any deductibles would have a material adverse effect on the Company's financial condition or results of operations. While we

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believe the Company maintains adequate insurance coverage, insurance may not fully cover every type of damage, interruption or other loss that might occur.  If we were to incur a significant loss for which we were not fully insured, it could have a material impact on our financial position, results of operations and cash flows.  In addition, there may be a timing difference between amounts we are required to pay in connection with a loss and amounts we receive from insurance as reimbursement. Any event that materially interrupts the revenues generated by our consolidated operations, or other losses that require us to make material expenditures not covered by insurance, could adversely affect our cash flows and financial condition and, accordingly, adversely affect the market price of our securities.

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NOTE H – CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Shown below are condensed consolidating financial statements for GMX Resources Inc. on a stand-alone, unconsolidated basis, its combined guarantor subsidiaries and its non-guarantor subsidiary as of June 30, 2012 and December 31, 2011 and for the three and six months ended June 30, 2012 and 2011. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

Condensed Consolidating Balance Sheets

	June 30, 2012
	Parent			Guarantors		Non-Guarantor		Eliminations			Consolidated
						(In thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	31,339		$	46	$	737	$	—		$	32,122
Restricted cash	4,325			—		—		—			4,325
Short term investments	6,008			—		—		—			6,008
Accounts receivable – interest owners	5,952			—		—		—			5,952
Accounts receivable – oil and natural gas revenues, net	7,150			152		—		(2,597		)	4,705
Accounts receivable - intercompany	15,565			13,197		1,000		(29,762		)	—
Derivative instruments	1,929			—		—		—			1,929
Inventories	326			—		—		—			326
Prepaid expenses and deposits	1,556			1		26		—			1,583
Assets held for sale	410			—		—		—			410
Total current assets	74,560			13,396		1,763		(32,359		)	57,360
OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD
Properties being amortized	1,104,383			713		71		—			1,105,167
Properties not subject to amortization	162,783			—		—		—			162,783
Less accumulated depreciation, depletion, and impairment	(1,003,510		)	—		—		—			(1,003,510		)
	263,656			713		71		—			264,440
PROPERTY AND EQUIPMENT, AT COST, NET	14,377			4,917		43,865		—			63,159
DERIVATIVE INSTRUMENTS	1,451			—		—		—			1,451
OTHER ASSETS	8,382			—		—		—			8,382
INVESTMENT IN SUBSIDIARIES	34,719			—		—		(34,719		)	—
TOTAL ASSETS	$	397,145		$	19,026	$	45,699	$	(67,078	)	$	394,792
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	11,545			—		37		—			11,582
Accounts payable - intercompany	13,450			16,225		87		(29,762		)	—
Accrued expenses	15,581			2,749		178		(2,597		)	15,911
Accrued interest	4,956			—		—		—			4,956
Revenue distributions payable	5,609			—		—		—			5,609
Short-term derivative instrument	1,141			—		—		—			1,141
Current maturities of long-term debt	51,256			—		—		—			51,256
Total current liabilities	103,538			18,974		302		(32,359		)	90,455
LONG-TERM DEBT, LESS CURRENT MATURITIES	362,987			—		—		—			362,987
DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS	608			—		—		—			608
OTHER LIABILITIES	8,415			—		—		—			8,415
EQUITY
Total GMX equity	(78,403		)	52		45,397		(45,449		)	(78,403		)
Noncontrolling interest	—			—		—		10,730			10,730
Total equity	(78,403		)	52		45,397		(34,719		)	(67,673		)
TOTAL LIABILITIES AND EQUITY	$	397,145		$	19,026	$	45,699	$	(67,078	)	$	394,792

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	December 31, 2011
	Parent			Guarantors		Non-Guarantor		Eliminations			Consolidated
						(In thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	98,118		$	3,672	$	703	$	—		$	102,493
Restricted cash	4,325			—		—		—			4,325
Accounts receivable – interest owners	8,607			—		—		—			8,607
Accounts receivable – oil and natural gas revenues, net	12,564			295		—		(5,777		)	7,082
Accounts receivable - intercompany	15,205			13,033		790		(29,028		)	—
Derivative instruments	—			—		—		—			—
Inventories	326			—		—		—			326
Prepaid expenses and deposits	2,574			2		79		—			2,655
Assets held for sale	1,999			46		—		—			2,045
Total current assets	143,718			17,048		1,572		(34,805		)	127,533
OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD
Properties being amortized	1,061,961			713		127		—			1,062,801
Properties not subject to amortization	147,224			—		—		—			147,224
Less accumulated depreciation, depletion, and impairment	(871,346		)	—		—		—			(871,346		)
	337,839			713		127		—			338,679
PROPERTY AND EQUIPMENT, AT COST, NET	15,531			5,216		45,111		—			65,858
DERIVATIVE INSTRUMENTS	—			—		—		—			—
OTHER ASSETS	10,131			—		—		—			10,131
INVESTMENT IN SUBSIDIARIES	35,980			—		—		(35,980		)	—
TOTAL ASSETS	$	543,199		$	22,977	$	46,810	$	(70,785	)	$	542,201
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	13,527			—		23		—			13,550
Accounts payable - intercompany	13,126			15,684		218		(29,028		)	—
Accrued expenses	17,263			6,056		293		(5,777		)	17,835
Accrued interest	3,256			—		—		—			3,256
Revenue distributions payable	5,980			—		—		—			5,980
Current maturities of long-term debt	26			—		—		—			26
Total current liabilities	53,178			21,740		534		(34,805		)	40,647
LONG-TERM DEBT, LESS CURRENT MATURITIES	426,805			—		—		—			426,805
DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS	—			—		—		—			—
OTHER LIABILITIES	7,476			—		—		—			7,476
EQUITY
Total GMX equity	55,740			1,237		46,276		(47,513		)	55,740
Noncontrolling interest	—			—		—		11,533			11,533
Total equity	55,740			1,237		46,276		(35,980		)	67,273
TOTAL LIABILITIES AND EQUITY	$	543,199		$	22,977	$	46,810	$	(70,785	)	$	542,201

19

Condensed Consolidating Statements of Operations

	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated
							(In thousands)
Three Months Ended June 30, 2012
TOTAL REVENUES	$	16,102		$	292		$	2,126		$	(2,237	)	$	16,283
COSTS AND EXPENSES
Lease operating	4,446			388			246			(2,192		)	2,888
Production taxes	556			—			—			—			556
Depreciation, depletion, and amortization	6,169			179			626			—			6,974
Impairment of oil and natural gas properties and assets held for sale	91,815			—			(125		)	—			91,690
General and administrative	6,499			321			27			(45		)	6,802
Total expenses	109,485			888			774			(2,237		)	108,910
Income (loss) from operations	(93,383		)	(596		)	1,352			—			(92,627		)
NON-OPERATING INCOME (EXPENSE)
Interest expense	(10,122		)	—			—			—			(10,122		)
Gain (loss) on conversion/extinguishment of debt	831			—			—			—			831
Interest and other income	35			—			—			—			35
Unrealized gain on derivatives	(11		)	—			—			—			(11		)
Equity income (loss) of subsidiaries	(226		)	—			—			226			—
Total non-operating expense	(9,493		)	—			—			226			(9,267		)
Income (loss) before income taxes	(102,876		)	(596		)	1,352			226			(101,894		)
INCOME TAX PROVISION	(1,418		)	—			—			—			(1,418		)
NET INCOME (LOSS)	(104,294		)	(596		)	1,352			226			(103,312		)
Net income attributable to noncontrolling interest	—			—			—			982			982
NET (LOSS) INCOME APPLICABLE TO GMX RESOURCES	(104,294		)	(596		)	1,352			(756		)	(104,294		)
Preferred stock dividends	1,837			—			—			—			1,837
NET (LOSS) INCOME APPLICABLE TO COMMON SHAREHOLDERS	$	(106,131	)	$	(596	)	$	1,352		$	(756	)	$	(106,131	)

20

	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated
							(In thousands)
Three Months Ended June 30, 2011
TOTAL REVENUES	$	32,370		$	746		$	3,174		$	(3,432	)	$	32,858
COSTS AND EXPENSES
Lease operating	4,649			1,161			271			(3,245		)	2,836
Production taxes	166			—			—			—			166
Depreciation, depletion, and amortization	12,493			187			624			—			13,304
Impairment of oil and natural gas properties and assets held for sale	11,508			5,353			—			—			16,861
General and administrative	7,228			469			96			(188		)	7,605
Total expenses	36,044			7,170			991			(3,433		)	40,772
Income (loss) from operations	(3,674		)	(6,424		)	2,183			1			(7,914		)
NON-OPERATING INCOME (EXPENSE)
Interest expense	(7,832		)	—			—			—			(7,832		)
Gain (loss) on conversion/extinguishment of debt	(67		)	—			—			—			(67		)
Interest and other income	82			(58		)	(12		)	—			12
Unrealized gain on derivatives	5,437			—			—			—			5,437
Equity income (loss) of subsidiaries	(6,057		)	—			—			6,057			—
Total non-operating expense	(8,437		)	(58		)	(12		)	6,057			(2,450		)
Income (loss) before income taxes	(12,111		)	(6,482		)	2,171			6,058			(10,364		)
INCOME TAX PROVISION	(1,436		)	—			—			—			(1,436		)
NET INCOME (LOSS)	(13,547		)	(6,482		)	2,171			6,058			(11,800		)
Net income attributable to noncontrolling interest	—			—			—			1,746			1,746
NET (LOSS) INCOME APPLICABLE TO GMX RESOURCES	(13,547		)	(6,482		)	2,171			4,312			(13,546		)
Preferred stock dividends	1,837			—			—			—			1,837
NET (LOSS) INCOME APPLICABLE TO COMMON SHAREHOLDERS	$	(15,384	)	$	(6,482	)	$	2,171		$	4,312		$	(15,383	)

21

	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated
							(In thousands)
Six Months Ended June 30, 2012
TOTAL REVENUES	$	33,234		$	718		$	4,328		$	(4,596	)	$	33,684
COSTS AND EXPENSES
Lease operating	8,975			865			639			(4,483		)	5,996
Production taxes	319			—			—			—			319
Depreciation, depletion, and amortization	12,829			357			1,253			—			14,439
Impairment of oil and natural gas properties and assets held for sale	120,815			—			(125		)	—			120,690
General and administrative	13,132			681			97			(113		)	13,797
Total expenses	156,070			1,903			1,864			(4,596		)	155,241
Income (loss) from operations	(122,836		)	(1,185		)	2,464			—			(121,557		)
NON-OPERATING INCOME (EXPENSE)
Interest expense	(20,824		)	—			(1		)	—			(20,825		)
Gain (loss) on conversion/extinguishment of debt	3,612			—			—			—			3,612
Interest and other income	108			—			—			—			108
Unrealized gain on derivatives	779			—			—			—			779
Equity income (loss) of subsidiaries	(592		)	—			—			592			—
Total non-operating expense	(16,917		)	—			(1		)	592			(16,326		)
Income (loss) before income taxes	(139,753		)	(1,185		)	2,463			592			(137,883		)
INCOME TAX PROVISION	(3,305		)	—			—			—			(3,305		)
NET INCOME (LOSS)	(143,058		)	(1,185		)	2,463			592			(141,188		)
Net income attributable to noncontrolling interest	—			—			—			1,870			1,870
NET (LOSS) INCOME APPLICABLE TO GMX RESOURCES	(143,058		)	(1,185		)	2,463			(1,278		)	(143,058		)
Preferred stock dividends	3,673			—			—			—			3,673
NET (LOSS) INCOME APPLICABLE TO COMMON SHAREHOLDERS	$	(146,731	)	$	(1,185	)	$	2,463		$	(1,278	)	$	(146,731	)

22

	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated
							(In thousands)
Six Months Ended June 30, 2011
TOTAL REVENUES	$	61,267		$	1,437		$	6,084		$	(6,553	)	$	62,235
COSTS AND EXPENSES
Lease operating	9,174			2,026			733			(6,200		)	5,733
Production taxes	549			—			—			—			549
Depreciation, depletion, and amortization	24,477			374			1,242			—			26,093
Impairment of oil and natural gas properties and assets held for sale	59,738			5,350			93			—			65,181
General and administrative	13,872			1,004			160			(353		)	14,683
Total expenses	107,810			8,754			2,228			(6,553		)	112,239
Income (loss) from operations	(46,543		)	(7,317		)	3,856			—			(50,004		)
NON-OPERATING INCOME (EXPENSE)
Interest expense	(15,853		)	—			(1		)	—			(15,854		)
Gain (loss) on conversion/extinguishment of debt	(176		)	—			—			—			(176		)
Interest and other income	206			—			76			—			282
Unrealized gain on derivatives	4,992			—			—			—			4,992
Equity income (loss) of subsidiaries	(6,544		)	—			—			6,544			—
Total non-operating expense	(17,375		)	—			75			6,544			(10,756		)
Income (loss) before income taxes	(63,918		)	(7,317		)	3,931			6,544			(60,760		)
INCOME TAX PROVISION	(2,868		)	—			—			—			(2,868		)
NET INCOME (LOSS)	(66,786		)	(7,317		)	3,931			6,544			(63,628		)
Net income attributable to noncontrolling interest	—			—			—			3,158			3,158
NET (LOSS) INCOME APPLICABLE TO GMX RESOURCES	(66,786		)	(7,317		)	3,931			3,386			(66,786		)
Preferred stock dividends	3,047			—			—			—			3,047
NET (LOSS) INCOME APPLICABLE TO COMMON SHAREHOLDERS	$	(69,833	)	$	(7,317	)	$	3,931		$	3,386		$	(69,833	)

23

Condensed Consolidating Statements of Cash Flows

	Parent			Guarantors			Non-Guarantor			Eliminations		Consolidated
							(In thousands)
Six Months Ended June 30, 2012
Net cash provided by (used in) operating activities	$	(7,825	)	$	(3,619	)	$	3,382		$	—	$	(8,062	)
Net cash provided by (used in) investing activities	(57,643		)	(7		)	(6		)	—		(57,656		)
Net cash provided by (used in) financing activities	(1,311		)	—			(3,342		)	—		(4,653		)
Net decrease in cash	(66,779		)	(3,626		)	34			—		(70,371		)
Cash and cash equivalents at beginning of period	98,118			3,672			703			—		102,493
Cash and cash equivalents at end of period	$	31,339		$	46		$	737		$	—	$	32,122
Six Months Ended June 30, 2011
Net cash provided by (used in) operating activities	$	31,411		$	(346	)	$	6,559		$	—	$	37,624
Net cash provided by (used in) investing activities	(193,833		)	(101		)	1,676			—		(192,258		)
Net cash provided by (used in) financing activities	164,412			—			(7,258		)	—		157,154
Net decrease in cash	1,990			(447		)	977			—		2,520
Cash and cash equivalents at beginning of period	1,468			564			325			—		2,357
Cash and cash equivalents at end of period	$	3,458		$	117		$	1,302		$	—	$	4,877

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 thereto, together with our discussion and analysis of our financial position and results of operations, included in our annual report on Form 10-K for the year ended December 31, 2011 (the “2011 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 2011 Form 10-K and in this document. Please read “Forward-Looking Statements” below.

General

We are an independent oil and gas company currently focused on development acreage in two oil shale resource plays in the Williston Basin (North Dakota/Montana), targeting the Bakken and Sanish-Three Forks Formations, and the DJ Basin (Wyoming), targeting the Niobrara Formation. Both resource plays are estimated to be 90% oil. Our natural gas resources are located in the East Texas Basin, in the Haynesville/Bossier ("H/B") gas shale and the Cotton Valley Sand Formation, where substantially all of our acreage is contiguous and held by production. We believe these oil and natural gas resource plays provide a substantial inventory of operated, high probability, repeatable, organic growth opportunities. The Bakken properties cover approximately 35,000 net acres and the Niobrara properties cover more than 40,000 net acres. The Company believes that having choices for operating in multiple basins and for focusing on oil or natural gas resources provides us with flexibility to allocate capital to achieve the highest risk-adjusted rate of return on our portfolio. We also intend to convert our unproved reserves in these areas into proved reserves. We may selectively acquire additional acreage in these areas in the normal course of business.

Our current focus is on increasing oil production and focusing our operations in McKenzie and Billings Counties, North Dakota, where we are currently operating six wells, have one rig operating and one well waiting on completion. We also have non-operating interests in five additional wells in this area.

In Wyoming, our Niobrara development has begun with two seismic shoots encompassing 135 and 204 square miles. Our first shoot and part of our second shoot are complete and we are evaluating the results. The remainder of our second shoot is expected to be completed in the second half of 2012.

We plan to commit almost all of our total capital expenditures in 2012 to our oil resources development. We expect that

24

increasing the oil percentage of our production will have positive economic benefits created by the current price gap that exists between oil and natural gas. We plan to continue to use hedging to mitigate commodity price risks for our oil and gas production.

Recent Events

On June 20, 2012, the New York Stock Exchange (NYSE) provided notice that the decline in the Company's share price has caused it to be out of compliance with the NYSE's continued listing standards. Under the NYSE's rules, in order to get back in compliance with the listing standard, both the ending share price and the average share price (over a consecutive 30-trading period) must exceed $1.00 within six months following receipt of the non-compliance notice. Notwithstanding the foregoing, if the Company determines to remedy the non-compliance by taking action that will require shareholder approval, such as a reverse stock split, the NYSE will continue to list the Company's common stock pending shareholder approval by no later than its next annual meeting, and the implementation of such action promptly thereafter. The Company will be back in compliance with its listing standard if the share price promptly exceeds $1.00 per share, and the price remains above the level for at least the following 30 trading days. The Company's common stock will continue to be listed and will trade on the NYSE subject to the Company's continued compliance with the NYSE's other applicable listing requirements.

On July 17, 2012, the Company announced a proposed sale of a portion of the Company's Cotton Valley Sand liquids rich natural gas properties located in East Texas. The Proved Developed and Producing wells are in the mature stage of production with shallow decline rates. In addition, the assets have additional upside through infill horizontal development. The Company currently expects that the sale of these properties will occur during the third quarter of 2012 and the proceeds will be used to fund the Company's Bakken drilling program.

The Company's balance on its 5.00% Convertible Notes due 2013 at year-end 2011 was $72.8 million. During 2012, the Company has completed a total of six separately negotiated debt-for-equity exchange transactions with holders of the 5.00% Convertible Notes. The debt for equity transactions have resulted in the issuance of 11,271,510 shares of common stock and has reduced the principal amount of the 5.00% Convertible Notes by $20.8 million leaving a principal balance of $52.0 million as of July 1, 2012. We continue to evaluate additional options for refinancing and/or repayment of these notes prior to their maturity in February 2013. See discussion of these options in Note A - Nature of Operations and Summary of Significant Accounting Policies.

25

The table below summarizes information concerning our operating activities in the three and six months ended June 30, 2012 compared to the three and six months ended June 30, 2011.

Summary Operating Data

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2012 (1)		2011			2012 (1)		2011
Production:
Oil (MBbls)	64		24			95		46
Natural gas (MMcf)	2,534		5,852			5,051		11,367
Natural gas liquids (MBbls)	50		88			195		153
Gas equivalent production (MMcfe)	3,217		6,524			6,793		12,563
Natural gas VPP volumes (MMcfe)	1,005		—			2,188		—
Gas equivalent production including VPP volumes (MMcfe)	4,222		6,524			8,981		12,563
Average daily production excluding VPP volumes (MMcfe)	35.3		71.7			37.3		69.4
Average daily production including VPP volumes (MMcfe)	46.4		71.7			49.3		69.4
Average Sales Price:
Oil (per Bbl)
Wellhead price	$	86.29	$	100.04		$	88.80	$	96.41
Effect of hedges, excluding gain or loss from ineffectiveness of derivatives	3.81		(1.79		)	2.57		(0.95		)
Total	$	90.10	$	98.25		$	91.37	$	95.46
Natural gas liquids (per Bbl)
Sales price	$	32.84	$	40.04		$	34.39	$	38.17
Effect of hedges, excluding gain or loss from ineffectiveness of derivatives	—		—			—		—
Total	$	32.84	$	40.04		$	34.39	$	38.17
Natural gas (per Mcf)
Wellhead price	$	1.66	$	3.87		$	1.64	$	3.77
Effect of hedges, excluding gain or loss from ineffectiveness of derivatives	1.85		0.68			1.98		0.74
Total	$	3.51	$	4.55		$	3.62	$	4.51
Average sales price, excluding gain or loss from ineffectiveness of derivatives (per Mcfe)	$	5.06	$	5.04		$	4.96	$	4.95
Operating and Overhead Costs (per Mcfe):
Lease operating expenses including VPP volumes	$	0.68	$	0.43		$	0.67	$	0.46
Effect of excluding VPP volumes on lease operating expenses	0.22		—			0.21		—
Lease operating expense excluding VPP volumes	$	0.90	$	0.43		$	0.88	$	0.46
Production and severance taxes including VPP volumes	$	0.13	$	0.03		$	0.04	$	0.04
Effect of excluding VPP volumes on production and severance taxes	0.04		—			0.01		—
Production and severance taxes excluding VPP volumes	$	0.17	$	0.03		$	0.05	$	0.04
General and administrative including VPP volumes	$	1.61	$	1.17		$	1.54	$	1.17
Effect of excluding VPP volumes on general and administrative	0.50		—			0.49		—
General and administrative excluding VPP volumes	$	2.11	$	1.17		$	2.03	$	1.17
Total cost including VPP volumes	$	2.42	$	1.63		$	2.25	$	1.67
Total cost excluding VPP Volumes	$	3.18	$	1.63		$	2.96	$	1.67
Other (per Mcfe):
Depreciation, depletion and amortization—oil and natural gas properties (excluding VPP volumes)	$	1.70	$	1.81		$	1.68	$	1.84

⁽¹⁾ For 2012, the amounts presented are net of the Volumetric Production Payment ("VPP") volumes, with exception of “Operating and Overhead Costs (per Mcfe),” which are presented gross and net of the VPP volumes.

26

Results of Operations for the Three Months Ended June 30, 2012 Compared to the Three Months Ended June 30, 2011

Oil and Natural Gas Sales. Oil and natural gas sales during the three months ended June 30, 2012 decreased 50% to $16.3 million compared to $32.9 million in the second quarter of 2011. The decrease in oil and gas sales was primarily due to a 51% decrease in production on a Bcfe-basis of which 30% of the decrease was attributable to natural gas volumetric production payment ("VPP") volumes of 1.0 Bcfe that were sold in the form of a term overriding royalty interest in December 2011 and the remainder of the decrease was a result of the natural decline from the Company's H/B production due to the suspension of the Company's H/B horizontal drilling program in mid-2011. The average price per barrel of oil, per barrel of natural gas liquids ("NGLs") and per thousand cubic feet (Mcf) of natural gas received (exclusive of ineffectiveness from derivatives) in the three months ended June 30, 2012 was $90.10, $32.84 and $3.51, respectively, compared to $98.25, $40.04 and $4.55, respectively, in the three months ended June 30, 2011. This represented a 8% decrease in oil prices, a 18% decrease in the average realized price in NGLs, and a 23% decrease in the average realized price of natural gas. Our realized sales price for natural gas, including revenue from NGLs and excluding the effect of hedges of $1.85 and $0.68, for the three months ended June 30, 2012 and 2011, respectively, was approximately 104% and 89% of the average NYMEX closing contract price for the respective periods. In the second quarter of 2012 and 2011, the conversion of natural gas to NGLs produced an upgrade of approximately $0.64 per Mcf and $0.42 per Mcf, respectively, for every Mcf of natural gas sold.

Natural gas production for the three months ended June 30, 2012 decreased to 2.5 Bcf compared to 5.9 Bcf for the three months ended June 30, 2011, a decrease of 57%. Including the VPP volumes of 1.0 Bcf, natural gas production decreased by 2.4 Bcf, or 41%. The decrease in natural gas production resulted primarily from the natural decline in the Company's H/B wells as a result of the suspension of the Company's H/B horizontal drilling program in mid-2011. The Company's last H/B well was completed and brought on line in August 2011.

Oil production for the three months ended June 30, 2012 increased 164% to approximately 64,100 Bbls, from approximately 24,300 Bbls for the three months ended June 30, 2011, as a result of the Company's new Bakken production. For the second quarter of 2012, the Company produced approximately 39,100 Bbls in the Bakken and approximately 25,000 Bbls in East Texas compared to the second quarter of 2011 when the Company only had East Texas oil production. Bakken and East Texas oil sales, excluding hedges, during the three months ended June 30, 2012 were $3.1 million and $2.4 million, respectively.

NGL production for the three months ended June 30, 2012 decreased to approximately 49,600 Bbls compared to approximately 87,600 Bbls for the three months ended June 30, 2011, a decrease of 43%. Due to the limitations in NGL infrastructure in the second quarter of 2012 and the resulting decrease in available processing capacity, the Company elected to sell a portion of our unprocessed gas in the Carthage Texas area for a total price that was greater than the combined estimated price of residue gas and the net processing upgrade. Since the NGLs can be left in or extracted from the gas stream, we will continue to make gas dispatch decisions based on maximizing the total sales value of the combined hydrocarbon stream.

For the three months ended June 30, 2012, as a result of hedging activities, excluding derivative ineffectiveness, we recognized an increase in oil and natural gas sales of $4.9 million compared to an increase in oil and natural gas sales of $3.9 million in the second quarter of 2011. In the second quarter of 2012, hedging, excluding ineffectiveness, increased the average natural gas sales price by $1.85 per Mcf compared to an increase in natural gas sales price of $0.68 per Mcf in the second quarter of 2011. The increase in oil and natural gas sales and sales price, as a result of hedging activities for the three months ended June 30, 2012, was mainly due to the amortization of $4.2 million in realized non-cash gain on our cash flow hedges that we monetized in the fourth quarter 2011. The remaining realized gain of $7.8 million in other comprehensive income will be amortized into earnings ratably through 2013. Our derivative contracts that have not been monetized on natural gas increased our natural gas sales by $0.5 million and $4.0 million for the three months ended June 30, 2012 and 2011, respectively. Our derivative contracts on oil increased our oil sales by $0.2 million and decreased our oil sales by $44,000 for the three months ended June 30, 2012 and 2011, respectively. The effect of our derivative contracts on oil increased the average oil sales price by $3.81 per Bbl for the three months ended June 30, 2012 and decreased it by $1.79 per Bbl for the three months ended June 30, 2011.

Lease Operations. Lease operations expense increased $0.1 million, or 2%, for the three months ended June 30, 2012, to $2.9 million, compared to $2.8 million for the three months ended June 30, 2011. Lease operations expense on a per thousand cubic fee equivalent (Mcfe) basis, excluding VPP volumes increased $0.47, or 109%, to $0.90 for the three months ended June 30, 2012 compared to $0.43 for the three months ended June 30, 2011. The increase in lease operating expenses in total and on a per Mcfe basis is due to higher lease operating expenses related to the Company's Bakken oil production and the impact of the volumetric production payment of $0.22 per Mcfe. For the three months ended June 30, 2012 and 2011, lease operations expense on a per Mcfe basis for East Texas and the Bakken was $0.82 and $2.35, respectively.

Production and Severance Taxes. Production and severance taxes increased 235% to $0.6 million in the three months ended June 30, 2012 compared to $0.2 million in the three months ended June 30, 2011. The increase in production and

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severance taxes is due to a higher amount of severance tax expense recorded in relation to the qualified reimbursements receivable, which offset severance tax expense, as compared the three months ended June 30, 2011.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $6.8 million, or 51%, to $6.5 million in the three months ended June 30, 2012 compared to $13.3 million for the three months ended June 30, 2011. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.70 per Mcfe in the three months ended June 30, 2012 compared to $1.81 per Mcfe in the three months ended June 30, 2011. This decrease in the rate per Mcfe is primarily due to the recent impairment charges recognized by the Company which has lowered the amount of oil and gas properties subject to amortization.

Impairment of oil and natural gas properties and assets held for sale. For the $91.7 million impairment charge recorded in the second quarter of 2012, $91.8 million was related to the impairment of oil and gas properties subject to the full cost ceiling test, which was offset by a gain of $0.1 million on the sale of assets held for sale. 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. Any excess of the net book value is generally written off as an expense. 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. Natural gas represented approximately 79% of the Company’s total production for the three months ended June 30, 2012. During the second quarter of 2012, the 12-month average of the first day of the month natural gas price decreased 16% from $3.73 per MMbtu at March 31, 2012 to $3.15 per MMbtu at June 30, 2012, contributing to the impairment for the second quarter of 2012. Of the $91.8 million impairment of oil and gas properties, $62.8 million was related to the decrease in natural gas and oil prices and $27.9 million was related to continued infrastructure and operational constraints impacting proved producing reserves in the Bakken. The Company anticipates positive Bakken reserve revisions in the future.

    General and Administrative Expense. General and administrative expense for the three months ended June 30, 2012 was $6.8 million, compared to $7.6 million for the three months ended June 30, 2011, a decrease of $0.8 million, or 11%, as a result of cost cutting measures implemented by the Company in early 2012. General and administrative expenses include $1.6 million and $1.2 million of non-cash compensation expense as of the three months ended June 30, 2012 and 2011, respectively. Non-cash compensation represented 24% and 16% of total general and administrative expenses, for the three months ended June 30, 2012 and 2011, 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.

Interest. Interest expense for the three months ended June 30, 2012 was $10.1 million compared to $7.8 million for the same period in 2011, an increase of $2.3 million or 29%. The increase in interest expense was primarily due to the Company's decision in 2012 to elect the PIK option ("PIK Election") on its $283.5 million of Senior Secured Notes due 2017 that allows for a 9% cash interest payment along with a 4% interest payment in the form of additional Senior Secured Notes resulting in an annual interest rate of 13%, as well as the increase in the amount of the outstanding debt between the periods as a result of the exchange offer completed in December 2011. As part of the exchange, certain parties purchased an additional $100 million of the Senior Secured Notes for a total issuance of $283.5 million of the new Senior Secured Notes due 2017. As a result of the PIK Election, the Company has accrued interest at a higher rate for the three months ended June 30, 2012, which amounted to $3.0 million for the three months ended June 30, 2012. For the three months ended June 30, 2011, only the $200 million of 11.375% Senior Notes due 2019 were outstanding.

For the three months ended June 30, 2012 and 2011, interest expense includes non-cash interest expense of $1.2 million and $1.4 million, respectively, related to the accounting for convertible bonds, our share lending agreement and deferred premiums on derivative instruments. Cash interest expense for the three months ended June 30, 2012 and 2011 was $8.0 million and $7.7 million, respectively, of which $3.0 million and $2.0 million, respectively, was capitalized to properties not subject to amortization on the consolidated balance sheets. The increase in cash interest expense of $0.3 million was mainly due to the Company's completion of an exchange offer in December 2011 for all but $2 million of the 11.375% Senior Notes due 2019 which resulted in the issuance of $283.5 million of new Senior Secured Notes due 2017.

Income Taxes. Income tax expense for the three months ended June 30, 2012 was $1.4 million as compared to $1.4 million in the same period in 2011. The income tax expense recognized in the three months ended June 30, 2012 and 2011, respectively, 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 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 non-controlling interest. Net income to non-controlling interest was $1.0 million for the three months ended June 30, 2012 compared to $1.7 million for the three months ended June 30, 2011. This decrease was due to lower natural gas production in East Texas.

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Results of Operations for the Six Months EndedJune 30, 2012 Compared to the Six Months EndedJune 30, 2011

Oil and Natural Gas Sales. Oil and natural gas sales during the six months ended June 30, 2012 decreased 46% to $33.7 million compared to $62.2 million in the six months ended June 30, 2011. The decrease in oil and gas sales was primarily due to a 46% decrease in production on a Bcfe-basis of which 38% was attributable to natural gas VPP volumes of 2.2 Bcfe that were sold in the form of a term overriding royalty interest in December 2011and the remainder was the result of the natural decline from the Company's H/B production due to the suspension of the Company's H/B horizontal drilling program in mid-2011. The average price per barrel of oil, per barrel of NGLs and Mcf of natural gas received (exclusive of ineffectiveness from derivatives) in the six months ended June 30, 2012 was $91.37, $34.39 and $3.62, respectively, compared to $95.46, $38.17 and $4.51, respectively, in the six months ended June 30, 2011. This represented a 4% decrease in oil prices, a 10% decrease in the average realized price in NGLs, and a 20% decrease in the average realized price of natural gas. Our realized sales price for natural gas, including revenue from NGLs and excluding the effect of hedges of $1.98 and $0.74, for the six months ended June 30, 2012 and 2011, respectively, was approximately 120% and 89% of the average NYMEX closing contract price for the respective periods. In the six months ended June 30, 2012 and 2011, the conversion of natural gas to NGLs produced an upgrade of approximately $1.33 per Mcf and $0.35 per Mcf, respectively, for every Mcf of natural gas sold.

Natural gas production for the six months ended June 30, 2012 decreased to 5.1 Bcf compared to 11.4 Bcf for the six months ended June 30, 2011, a decrease of 56%. Including VPP volumes of 2.2 Bcf, natural gas production decreased by 4.1 Bcf, or 36%. The decrease in natural gas production resulted primarily from the natural decline in the Company's H/B wells as a result of the suspension of the Company's H/B horizontal drilling program in mid-2011. The Company's last H/B well was completed and brought on line in August 2011.

Oil production for the six months ended June 30, 2012 increased 107% to approximately 95,100 Bbls, from approximately 45,900 Bbls for the six months ended June 30, 2011, as a result of the Company's new Bakken production. For the first six months of 2012, the Company produced approximately 53,400 Bbls in the Bakken and approximately 41,700 Bbls in East Texas compared to only having East Texas oil production in the first six months of 2011. East Texas and Bakken oil sales during the six months ended June 30, 2012 was $4.1 million and $4.4 million, respectively.

NGL production for the six months ended June 30, 2012 increased to approximately 195,100 Bbls compared to approximately 153,400 Bbls for the six months ended June 30, 2011, an increase of 27%. This increase was due primarily to a change in the dispatch of our natural gas to plants with higher NGL recoveries and plant efficiencies, which first became available to us in April 2011 and continued to expand their capacity to process our gas throughout 2011. This was partially offset by the Company's decision to sell a portion of our unprocessed gas in the Carthage Texas area for a total price that was greater than the combined estimated price of residue gas and the net processing upgrade. Since the NGLs can be left in or extracted from the gas stream, we will continue to make gas dispatch decisions based on maximizing the total sales value of the combined hydrocarbon stream.

For the six months ended June 30, 2012, as a result of hedging activities, excluding derivative ineffectiveness, we recognized an increase in natural gas sales of $10.0 million compared to an increase in natural gas sales of $8.4 million in the six months ended June 30, 2011. For the six months ended June 30, 2012, hedging, excluding ineffectiveness, increased the average natural gas sales price by $1.98 per Mcf compared to an increase in natural gas sales price of $0.74 per Mcf in the six months ended June 30, 2011. The increase in natural gas sales and sales price, as a result of hedging activities for the six months ended June 30, 2012, was mainly due to the amortization of $10.2 million of realized non-cash gain on our cash flow hedges that we monetized in the fourth quarter 2011. Our derivative contracts that have not been monetized on natural gas increased our natural gas sales by $0.5 million and $8.4 million for the six months ended June 30, 2012 and 2011, respectively. Our derivative contracts on oil increased our oil sales by $0.2 million and decreased our oil sales by $44,000 for the six months ended June 30, 2012 and 2011, respectively. The effect of our derivative contracts on oil increased the average oil sales price by $2.57 per Bbl for the six months ended June 30, 2012 and decreased it by $0.95 per Bbl for the six months ended June 30, 2011.

Lease Operations. Lease operations expense increased $0.3 million, or 5%, for the six months ended June 30, 2012, to $6.0 million, compared to $5.7 million for the six months ended June 30, 2011. Lease operations expense on a per Mcfe basis, excluding VPP volumes increased $0.42, or 91.3%, to $0.88 for the six months ended June 30, 2012 compared to $0.46 for the six months ended June 30, 2011. The increase in lease operating expenses in total and on a per Mcfe basis is due to higher lease operating expenses related to the Company's Bakken oil production and the impact of the VPP of $0.21 per Mcfe. For the six months ended June 30, 2012 and 2011, lease operations expense on a per Mcfe basis for East Texas and the Bakken was $0.81 and $2.59, respectively.

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

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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 42% to $0.3 million in the six months ended June 30, 2012 compared to $0.5 million in the six months ended June 30, 2011. The decrease in production and severance taxes is due to due to a lower amount of severance tax expense recorded in relation to the qualified reimbursements receivable, which offset severance tax expense, as compared the six months ended June 30, 2011.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $12.1 million, or 46%, to $14.0 million in the six months ended June 30, 2012 compared to $26.1 million for the six months ended June 30, 2011. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.68 per Mcfe in the six months ended June 30, 2012 compared to $1.84 per Mcfe in the six months ended June 30, 2011. This decrease in the rate per Mcfe is primarily due to the recent impairment charges recognized by the Company which has lowered the amount of oil and gas properties subject to amortization.

Impairment of oil and natural gas properties and assets held for sale. Of the $120.7 million impairment charge recorded in the six months ended June 30, 2012, $120.8 million was related to the impairment of oil and gas properties subject to the full cost ceiling test, which was offset by a gain of $0.1 million on the sale of assets held for sale. 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. Any excess of the net book value is generally written off as an expense. 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. Natural gas represented approximately 74% of the Company’s total production for the six months ended June 30, 2012. During the six months ended June 30, 2012, the 12-month average of the first day of the month natural gas price decreased 24% from $4.12 per MMbtu at December 31, 2011 to $3.15 per MMbtu at June 30, 2012, contributing to the impairment for the six months ended June 30, 2012. Of the $120.8 million impairment of oil and gas properties, $94.6 million was related to the decrease in natural gas and oil prices and $19.8 million was related to continued infrastructure and operational constraints impacting proved producing reserves in the Bakken. The Company anticipates positive reserve revisions in the future.

    General and Administrative Expense. General and administrative expense for the six months ended June 30, 2012 was $13.8 million, compared to $14.7 million for the six months ended June 30, 2011, a decrease of $0.9 million, or 6%. General and administrative expenses include $2.3 million and $2.2 million of non-cash compensation expense as of the six months ended June 30, 2012 and 2011, respectively. Non-cash compensation represented 17% and 15% of total general and administrative expenses, for the six months ended June 30, 2012 and 2011, 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.

Interest. Interest expense for the six months ended June 30, 2012 was $20.8 million compared to $15.9 million for the same period in 2011, an increase of $4.9 million or 31%. The increase in interest expense was primarily due to the Company's decision in 2012 to elect the PIK Election on its Senior Secured Notes due 2017 that allows for a 9% cash interest payment along with a 4% interest payment in the form of additional Senior Secured Notes resulting in an annual interest rate of 13%, as well as, the increase in the amount of the outstanding debt between the periods as a result of the exchange offer completed in December 2011. As part of the exchange, certain parties purchased an additional $100 million of the Senior Secured Notes, for a total issuance of $283.5 million of the new Senior Secured Notes due 2017. As a result of the PIK Election, the Company has accrued interest at a higher rate for the six months ended June 30, 2012, which amounted to $6.1 million for the six months ended June 30, 2012. For the six months ended June 30, 2011, the Company did not have outstanding any Senior Secured Notes due 2017 and incurred a lower interest expense relating to its then-outstanding indebtedness.

For the six months ended June 30, 2012 and 2011, interest expense includes non-cash interest expense of $2.4 million and $2.9 million, respectively, related to the accounting for convertible bonds, our share lending agreement and deferred premiums on derivative instruments. Cash interest expense for the three months ended June 30, 2012 and 2011 was $16.3 million and $14.2 million, respectively, of which $5.8 million and $3.0 million, respectively, was capitalized to properties not subject to amortization on the consolidated balance sheets. The increase in cash interest expense of $2.1 million was mainly due to the Company's completion of an exchange offer in December 2011, for all but $2 million of the 11.375% Senior Notes due 2019 which resulted in the issuance of new Senior Secured Notes due 2017.

Income Taxes. Income tax expense for the six months ended June 30, 2012 was $3.3 million as compared to $2.9 million in the same period in 2011. The income tax expense recognized in the three months ended June 30, 2012 and 2011, respectively, 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 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.

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Net income to non-controlling interest. Net income to non-controlling interest was $1.9 million for the six months ended June 30, 2012 compared to $3.2 million for the six months ended June 30, 2011. This decrease was due to lower natural gas production in East Texas.

Net Loss and Net Loss Per Share

Net Loss and Net Loss Per Share—Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011. For the three months ended June 30, 2012, we reported a net loss applicable to common shareholders of $106.1 million, and for the three months ended June 30, 2011 we reported a net loss applicable to common shareholders of $15.4 million. Net loss per basic and fully diluted share was $1.52 for the second quarter of 2012 compared to net loss per basic and fully diluted share of $0.28 for the second quarter of 2011.

Net Loss and Net Loss Per Share—Six Months EndedJune 30, 2012 Compared to Six Months EndedJune 30, 2011. For the six months ended June 30, 2012, we reported a net loss applicable to common shareholders of $146.7 million, and for the six months ended June 30, 2011 we reported a net loss applicable to common shareholders of $69.8 million. Net loss per basic and fully diluted share was $2.23 for the six months ended June 30, 2012 compared to net loss per basic and fully diluted share of $1.43 for the six months ended June 30, 2011.

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 oil and natural gas prices, we have historically entered into swaps, three-way collars and put spreads. We plan to continue to hedge oil and natural gas in the future to mitigate our commodity price risk.

As of June 30, 2012, we had cash, cash equivalents and short-term investments of $42.5 million, including $4.3 million in restricted cash and $6.0 million in short-term investments. Through the period ended June 30, 2012, we have funded our operating expenses and capital expenditures through operating cash flows and from capital raised in December of 2011 which included $100 million from a bond exchange of our 11.375% Senior Noted due 2019 for our new Senior Secured Notes due 2017, $49.7 million in connection with the VPP, and $18.5 million from the December 2011 monetization of the Company's then existing hedge portfolio.

We continually review our drilling and capital expenditure plans and may change the amount we spend based on industry and market conditions and the availability of capital. In the first six months of 2012, our cash outlay for capital expenditures was $51.6 million. We anticipate funding approximately $100 million of cash capital expenditures in 2012 with cash on hand and asset sales or other potential capital market activities. In July 2012, we announced our intent to monetize a portion of our East Texas Cotton Valley Sand assets which would be used to fund our 2012 and 2013 capital expenditure budget. Our 2012 capital expenditure budget will focus on our Bakken development plans particularly in McKenzie and Billings Counties of North Dakota. In the Bakken, we are currently running one drilling rig. Based on available liquidity, we plan to add a second rig in the Bakken during the third or fourth quarter of 2012. In the Niobrara, we will continue to evaluate our seismic work and surrounding well results from other operators which may facilitate a partial sale or joint venture on our Niobrara acreage.

During the first half of 2012, we entered into separate exchange agreements with various holders of our 5.00% Convertible Notes. Pursuant to these agreements, as consideration for the surrender by the holders of $20,753,000 aggregate principal amount of the 5.00% Convertible Notes, we issued to the holders an aggregate of 11,271,510 shares of our common stock, par value $0.001 per share (the “Common Stock"), along with cash consideration relating to accrued and unpaid interest. These issuances of the Common Stock were effected pursuant to Section 3(a)(9) of the Securities Act of 1933. We continue to evaluate additional options for refinancing and repayment of these notes to address their maturity in February 2013.

In order to protect us against the financial impact of a decline in oil and natural gas prices, we have an active hedging program. In March 2012, we executed fixed price natural gas swaps against the NYMEX for the period of July 2012 through December 2013.  For the last six months of 2012, we swapped 2.57 Bcf at $2.60 and for all of 2013 we swapped 4.24 Bcf at $3.50. In connection with these swaps, we also entered into a basis swap in which we locked in a natural gas price differential between the NYMEX and the Houston Ship Channel at $0.08. The combination of these trades effectively locks in a sales price to GMXR of $2.52 for 2.57 Bcf during the six nine months of 2012, and $3.42 for 4.24 Bcf during 2013. In May 2012, we added a $3.20-$2.50 natural gas costless collar for 0.58 Bcf of production over the last six months of 2012. In addition, we added a $3.68 swap with a $3.00 sold put to create an enhanced natural gas swap for approximately 1 Bcf of 2013 production.

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In March 2012, we executed fixed price crude oil swaps against the NYMEX for July 2012 through December 2013. For the last six months of 2012, we swapped 24,907 barrels at $106.40 and for all of 2013 we created a $106.40-$65.50 put spread for 41,975 barrels. For 2014, we executed a costless three-way collar for 35,528 barrels with a ceiling of $114.10, a floor of $100 and a sold put of $80. We also bought $100-$90 put spreads for 19,421 barrels for the last six months of 2012, $100 puts for 26,654 barrels in 2013, and $95-$75 put spreads for 19,893 barrels in 2014. In May 2012, we swapped 30,360 barrels of crude oil at $96.50 for the last six months of 2012, executed a $90-$70 crude oil put spread for 38,325 barrels in 2013, and a $90-$70 crude oil put spread for 36,500 barrels in 2014.

Our strategy is to use swaps and costless collars to protect our flowing proved developed production, and use puts and put spreads to establish floors for our proved undeveloped production.  Since the forward prices for oil are less than the current prices for oil, our structure allows us to preserve the optionality benefits of oil price increases.  As we bring on new wells, we plan to increase our hedges to establish floors and protect revenues.

Cash Flow—Six Months EndedJune 30, 2012 Compared to Six Months EndedJune 30, 2011

In the six months ended June 30, 2012 and 2011, we spent $51.6 million and $192.3 million, respectively, in oil and natural gas acquisitions and development activities and related property and equipment, net of proceeds received from sales. These investments were funded during the six months ended June 30, 2012 by cash on hand and from capital raised in December of 2011 which included $100 million from a bond exchange of our 11.375% Senior Notes for our new Senior Secured Notes, $49.7 million in connection with the VPP, and $18.5 million from the monetization of the Company's hedge portfolio. Cash flow provided by operating activities in the six months ended June 30, 2012 was $(8.1) million compared to $37.6 million in the six months ended June 30, 2011.

For a discussion of our derivative activity, please also see “Capital Resources and Liquidity,” “Quantitative and Qualitative Disclosures About Market Risk” and Note C to the notes to unaudited financial statements included in this report.

Other Debt

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. These convertible notes are unsecured.

In March 2011, we completed a tender offer and the Company retired $50 million aggregate principal amount of the 5.00% Convertible Notes. During the first six months of 2012, we entered into separate exchange agreements with various holders of our 5.00% Convertible Notes due 2013. Pursuant to these agreements, as consideration for the surrender by the holders of $20,753,000 aggregate principal amount of the 5.00% Convertible Notes, we issued to the holders an aggregate of 11,271,510 shares of our Common Stock, along with cash consideration relating to accrued and unpaid interest. These issuances of Common Stock were effected pursuant to Section 3(a)(9) of the Securities Act of 1933. We continue to evaluate additional options for refinancing and repayment of these notes to address their maturity in February 2013. See discussion of these options in Note A - Nature of Operations and Summary of Significant Accounting Policies.

The 5.00% Convertible Notes mature in February 2013, and bear interest at a rate of 5.00% per year, payable semi-annually 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.

The 4.50% Convertible Notes mature in May 2015, and bear interest at a rate of 4.50% per year, payable semi-annually 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.

We were in compliance with the terms of the 5.00% Convertible Notes and the 4.50% Convertible Notes as of June 30, 2012. For further discussion of our convertible notes, please also read Note B to the notes to unaudited financial statements included in this report.

Senior Notes. On February 9, 2011, we successfully completed the issuance and sale of $200,000,000 aggregate principal amount of 11.375% Senior Notes due 2019. In December 2011, 99% of the 11.375% Senior Notes were converted to new Senior Secured Notes due 2017, which resulted in $1,970,000 of 11.375 % Senior Notes outstanding as of December 31, 2011. All covenants were terminated upon the conversion. We were in compliance with the terms of the 11.375% Senior Notes at June 30, 2012. For further discussion of our 11.375% Senior Notes, please also read Note B to the notes to unaudited financial statements included in this report.

Senior Secured Notes due 2017. On December 19, 2011, the Company executed an Indenture among the Company, the guarantors party thereto and U.S. Bank National Association, as trustee. As a result, the Company issued $283,475,000

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aggregate principal amount of Senior Secured Notes due 2017 pursuant to the Senior Secured Notes Indenture. The Senior Secured Notes are fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by each of the Company's existing and future domestic restricted subsidiaries (the “Guarantors”). All of the Company's existing subsidiaries other than Endeavor Gathering, LLC are domestic restricted subsidiaries and Guarantors.

Under the terms of the Senior Secured Notes Indenture, interest on the Senior Secured Notes will:

•accrue from the date of issuance of the Senior Secured Notes or, if interest has already been paid, from the most recent interest payment date;

•unless the Company makes a PIK Election with respect to an interest period, accrue for such interest period at the rate of 11.0% per annum, payable in cash, in arrears;

•if the Company makes a PIK Election with respect to an interest period, accrue for such interest period at the rate of 13.0% per annum in the aggregate, of which (i) 9.0% per annum shall be payable in cash, in arrears, and (ii) 4.0% per annum shall be payable in the form of additional notes (in minimum denominations of $1,000 and integral multiples thereof, with any fractional additional notes being paid in cash), in arrears;

•be payable on each June 1 and December 1, commencing June 1, 2012, to holders of record of the Senior Secured Notes as of the May 15 and November 15 immediately preceding the relevant interest payment date; and

•be computed on the basis of a 360-day year comprised of twelve 30-day months.

For the interest payment due June 1, 2012, the Company chose the PIK Election and as a result issued $5.1 million of additional Senior Secured Notes as part of the interest payment to bring the outstanding principal balance to $288.6 million as of June 30, 2012.

The Senior Secured Notes will mature on December 1, 2017 and will be secured by first-priority perfected liens on substantially all right, title and interest in or to substantially all of the assets and properties owned or acquired by the Company and the Guarantors (the “Collateral”) The Collateral obligations are governed by, among other security documents, the Security Agreements.

The Senior Secured Notes Indenture restricts, among other things, the Company’s and its restricted subsidiaries’ ability to:

•incur or guarantee additional indebtedness or issue certain preferred stock;

•pay dividends or make other distributions;

•issue capital stock of our restricted subsidiaries;

•transfer or sell assets, including the capital stock of our restricted subsidiaries;

•make certain investments or acquisitions;

•grant liens on our assets;

•incur dividend or other payment restrictions affecting our restricted subsidiaries;

•enter into certain transactions with affiliates; and

•merge, consolidate or transfer all or substantially all of our assets.

The covenants are subject to important exceptions and qualifications.

We were in compliance with the terms of the Senior Secured Notes at June 30, 2012. For further discussion of our Senior Secured Notes, please also read Note B to the notes to unaudited financial statements included in this report.

Working Capital

At June 30, 2012, we had a working capital deficit of $33.1 million. Included in current liabilities is $51.2 million related to the 5.00% Convertible Notes due 2013. See "Capital Resources and Liquidity" regarding the maturity of these notes. We are continuing to evaluate and pursue alternatives to address our working capital needs and the maturity of our 5.00% Convertible Notes due in February 2013, including the potential sales of assets and issuances of securities. See Note A - Nature

33

of Operations and Summary of Significant Accounting Policies, for further information regarding our alternatives.

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 2011 Form 10-K. There have been no changes in such policies.

Contractual Obligations

Our contractual obligations are summarized in our 2011 Form 10-K.

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.

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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 2011 Form 10-K and in this document. We may also make material acquisitions or divestitures or enter into financing transactions. None of these events can be predicted with certainty or taken into consideration in the forward-looking statements.

Including, but not limited to, 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.

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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. Decreases 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.

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.

The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted in 2010 (the “Dodd-Frank Act”) provides for new statutory and regulatory requirements for swaps and other financial derivative transactions, including oil and gas hedging transactions. Under the Dodd-Frank Act, we will be required to transact “clearable” derivatives on a Designated Contract Market (“DCM”) or a Swap Execution Facility (“SEF”) such as a futures exchange or board of trade registered with the Commodity Futures Trading Commission (“CFTC”).  All derivative transactions including those that are not clearable on such a platform and are therefore executed on an over-the-counter, bi-lateral basis may be subject to new requirements that involve recordkeeping and reporting requirements, position limits and additional cash collateral or margin requirements.  The Dodd-Frank Act requires the CFTC, federal regulators of banks and other financial institutions, or the prudential regulators, and the SEC to promulgate rules implementing the new law.

On October 18, 2011, the CFTC issued its final position limits rules under the Dodd-Frank Act.  The position limit rules enumerated certain energy futures contracts as referenced contracts including NYMEX Light Sweet Crude Oil, New York Harbor Gasoline Blendstock, New York Harbor Heating Oil and Henry Hub Natural Gas.  Any referenced contract or associated contracts directly or indirectly linked to a referenced contract will be subject to the new position limits rules. These rules include spot month limits and non-spot month limits which can only be exceeded by positions that meet certain criteria to qualify as a Bona Fide Hedge.  Invoking Bona Fide Hedges will require new reporting requirements including the reporting of anticipatory transactions, transactions relying on pass through hedge exemptions and reporting where certain visibility levels are met or exceeded. The position limit rules will go into effect 60 days after the term “swap” is defined by the CFTC.  While there is still some uncertainty with respect to how the enumerated bona fide hedging qualifications will be interpreted, we anticipate that substantially all of our derivative transactions would qualify as Bona Fide Hedges.

On July 14, 2011, the CFTC granted temporary exemptive relief from certain provisions of the Commodity Exchange Act that otherwise would have taken effect on July 16, 2011, the general effective date of title VII of the Dodd-Frank Act.  On October 25, 2011, the CFTC proposed to extend the exemptive relief beyond the December 31, 2011 expiration date.  On December 19, 2011, the CFTC issued a Final Order regarding the effective date for swap regulation, which addressed the comments received on the October 25, 2011, Notice of Proposed Amendment, and extended the potential latest expiration date of the exemptive relief to July 16, 2012.  The CFTC continues to make progress on its rulemaking efforts and has not yet indicated an earlier expiration date for the exemptive relief granted.

On December 20, 2011, the CFTC approved two final rules that addressed how swap data will be reported to regulators and separately to the public.  One rule established recordkeeping requirements and a regulatory reporting regime for swap markets.  The other rule established a reporting regime for the public dissemination of swap transaction data in real-time.  Both rules affect swap dealers, major swap participants, swap counterparties that are neither swap dealers or major swap participants including end-users, swap data repositories, swap execution facilities, designated contract markets and derivatives clearing organizations.  While we do not believe the internal costs of reporting will be material to us, we have not been able to assess the full impact of these rules on our counterparties and our marketing and hedging activities.  Costs of compliance by our counterparties, particularly with the use of pass through hedge exemptions, will likely be passed on to customers such as ourselves, thus decreasing the benefits to us of hedging transactions and reducing our profitability.  In addition, the new recordkeeping and reporting rules expose us to the risk of financial penalties or disqualifications of transactions as Bona Fide Hedges due to potential failures in compliance with the documentation requirements.

The CFTC has not yet released final rules on margin or collateral requirements; however, it is possible that any new rules will increase the amount of cash required to support exchange and over-the-counter derivative transactions.  The majority of our financial derivative transactions used for hedging purposes are currently executed and cleared over exchanges that already require the posting of margins or other collateral based on initial and variation margin requirements.  Depending on the rules and definitions adopted by the CFTC, we might in the future be required to provide additional cash margin, new cash collateral or other collateral for our commodities hedging transactions whether cleared over an exchange or over-the-counter.

The new legislation and any new regulations could significantly increase the cost of derivative contracts (including

36

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 our 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 June 30, 2012:

Effective Date	Maturity Date	Notional Amount Per Month	Remaining Notional Amount as of June 30, 2012	Additional Put Options	Floor	Ceiling	Designation under ASC 815
Natural Gas (MMBtu):
7/1/2012	12/31/2012	429,113	2,574,680		$2.60	$2.60	Not designated
7/1/2012	12/31/2012	97,184	583,104		$2.50	$3.20	Not designated
1/1/2013	12/31/2013	353,559	4,242,710		$3.50	$3.50	Not designated
1/1/2013	12/31/2013	82,240	986,876	$3.00	$3.68	$3.68	Not designated
Crude Oil (Bbls):
7/1/2012	12/31/2012	5,060	30,360		$96.50	$96.50	Not designated
7/1/2012	12/31/2012	3,237	19,421	$90.00	$100.00		Not designated
7/1/2012	12/31/2013	3,749	67,489		$106.40	$106.40	Not designated
1/1/2013	12/31/2013	3,498	41,975	$65.50	$106.40		Not designated
1/1/2013	12/31/2013	3,194	38,325	$70.00	$90.00		Not designated
1/1/2013	12/31/2013	2,221	26,654		$100.00		Not designated
1/1/2014	12/31/2014	2,961	35,528	$80.00	$100.00	$114.10	Not designated
1/1/2014	12/31/2014	1,658	19,893	$75.00	$95.00		Not designated
1/1/2014	12/31/2014	3,042	36,500	$70.00	$90.00		Not designated

All of the above natural gas contracts are settled against NYMEX and all oil contracts are settled against NYMEX Light Sweet Crude. The NYMEX and NYMEX Light Sweet Crude have historically had a high degree of correlation with actual prices received by the Company.

The net fair value of our natural gas and oil derivative contracts in effect at June 30, 2012 was $1.8 million, of which $1.9 million is classified as a current asset, $1.5 million is classified as a long-term asset, $1.1 million is classified as a current liability and $0.5 million is classified as a long-term liability.

Based on the monthly notional amount for natural gas in effect at June 30, 2012, a hypothetical $0.10 increase in natural gas prices would have decreased the fair value from our natural gas swaps and options by $0.7 million, and a $0.10 decrease in natural gas prices would have increased the fair value from our natural gas swaps and option b $0.7 million. Based on the monthly notional amount for crude oil in effect at June 30, 2012, a hypothetical $1.00 increase would have decreased the fair value of our oil derivatives by $0.1 million and a $1.00 decrease in oil prices would have increased the fair value of our oil derivatives by $0.1 million.

Interest Rate Risk

We terminated our revolving bank credit facility during December 2011, and currently have no indebtedness for borrowed money based on a floating interest rate.

Our $52.0 million of 5.00% Convertible Notes, $86.3 million of 4.50% Convertible Notes, $2.0 million of 11.375% Senior Notes have fixed interest rates, and our $288.6 million of Senior Secured Notes have an interest rate fixed at either 11.0% per annum or the rate of 13% applicable to a PIK Election.

ITEM 4. Controls and Procedures.

Evaluation of disclosure controls and procedures as of June 30, 2012. As of the end of the period covered by this

37

quarterly report, we have evaluated, 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.

Our principal executive officer and our principal financial officer do not expect that our disclosure controls or our internal controls will prevent all error and all fraud. The design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be considered relative to their cost. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that we have detected all of our control issues and all instances of fraud, if any. The design of any system of controls also is based partly on certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving our stated goals under all potential future conditions.

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.

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PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings.

A putative class action lawsuit was filed by the Northumberland County Retirement System and Oklahoma Law Enforcement Retirement System (collectively, the “Nothumberland Plaintiffs”)in the District Court in Oklahoma County, Oklahoma, purportedly on March 10, 2011, against the Company and certain of its officers along with certain underwriters of the Company's July 2008, May 2009 and October 2009 public offerings. Discovery requests and summons were filed and issued in late April 2011. The complaint alleges that the registration statement and the prospectus for contained material misstatements and omissions and seeks damages under Sections 11, 12 and 15 of the Securities Act of 1933 of an unspecified equitable relief. Defendants removed the case to federal court on May 12, 2011 and filed motions to dismiss on June 20, 2011. Plaintiffs filed a motion to remand the case to state court on June 10, 2011, and Defendants filed an opposition to that motion. By order dated November 16, 2011, the court denied Plaintiffs' motion to remand. On February 3, 2012, Plaintiffs moved to be appointed lead plaintiff under the Private Securities Litigation Reform Act. By order dated July 3, 2012, the Court appointed the Northumberland Plaintiffs lead plaintiff. By August 16, 2012, Plaintiffs are expected to elect to move forward with their existing complaint or to file an amended complaint, with Defendants' responses thereto expected to be filed later in 2012. We are currently unable to assess the probability of loss or estimate a range of potential loss, if any, associated with the securities class action case, which is at an early stage.

On August 5, 2011, an individual filed a shareholders' derivative action in the United States District Court for the Western District of Oklahoma, for the Company's benefit, as nominal defendant, against the Company's Chief Executive Officer, President, Chief Financial Officer, and certain members of the Company's board of directors. The complaint alleges breaches of fiduciary duty, waste of corporate assets, and unjust enrichment on the part of each of the named defendants and is premised on substantially the same facts alleged in the above-described securities lawsuit. The complaint seeks unspecified amounts of compensatory damages, implementation of certain corporate governance changes, and disgorgement of compensation and trading profits from the individual defendants, as well as interest and costs, including legal fees from the defendants. The Company is a nominal defendant, and the complaint does not seek any damages against the Company; however, the Company may have indemnification obligations to one or more of the defendants under the Company's organizational documents. On October 17, 2011, the individual defendants and the Company as nominal defendant filed motions to dismiss the complaint for failure to make demand, or in the alternative, to stay the derivative action pending the outcome of the securities lawsuit. The case is currently stayed pending the outcome of the motions to dismiss that are expected to be filed with respect to the securities lawsuit described above. On March 23, 2012, an additional plaintiff filed a similar derivative action in the United States District Court for the Western District of Oklahoma. The parties agreed to consolidate this case with the existing federal court derivative action. The federal court derivative actions have been consolidated, and the cases are stayed pending the outcome of the motions to dismiss the securities lawsuit described above. We are currently unable to assess the probability of loss or estimate a range of potential loss, if any, associated with this case.

On February 7 and 9, 2012, two individuals filed separate shareholder derivative actions in the District Court of Oklahoma County, in the State of Oklahoma, for the Company's benefit, as nominal defendant, against the Company's Chief Executive Officer, President, Chief Financial Officer, and each member of the Company's board of directors. The petitions assert claims and seek relief similar to those asserted and sought in the federal court derivative action described above. Plaintiffs filed a motion to consolidate the two state court derivative actions, and the court consolidated the two actions. The parties have agreed that plaintiffs will file an amended and consolidated petition after the plaintiffs in the federal securities action described above file their amended complaint. On April 9, 2012, defendants filed a motion to dismiss, a motion to stay, and a motion for protection from discovery. By stipulation dated May 29, 2012, the parties agreed to stay these cases pending the outcome of the motions to dismiss the securities lawsuit described above and to stay discovery. We are currently unable to assess the probability of loss or estimate a range of potential loss, if any, associated with this case.

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 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 2011 Form 10-K.

39

Our future performance depends on our ability to raise equity capital.

As of June 30, 2012, we had approximately $32.1 million of cash on hand and, including $51.2 million aggregate principal amount of our 5.00% Convertible Notes due in February 2013, a $33.1 million working capital deficit. While we believe the current fair value of our total assets, including our oil and gas properties, exceeded their book value as of June 30, 2012, our capital as stated in accordance with generally accepted accounting principles indicated a deficit in shareholders' equity, due principally to impairments and net losses recorded. Our future performance will continue to depend on our ability to raise additional equity capital. We expect that lower commodity prices could result in further impairments being recorded on our assets, which could constrain our ability to incur, or affect the pricing of, additional debt or equity financings, which could adversely affect our ability to operate our business, including drilling and proving up additional recoverable reserves.

Our ability to repay our 5.00% Convertible Notes due in February 2013 with cash is also limited under the indenture for our Senior Secured Notes, and these limitations may require us to issue equity in order to pay cash for, or to otherwise satisfy, the payment of such notes at or prior to their maturity. To the extent required to repay our 5.00% Convertible Notes, our inability to issue sufficient equity could result in a default of our obligations under these notes and/or have a material adverse impact on our financial condition and liquidity. Similarly, the issuance of equity to meet our obligations under these or other notes could have a dilutive and adverse impact on our common stock.

We may not be able to generate enough cash flow to meet our debt obligations.

We expect our earnings and cash flow to vary significantly from year to year due to the nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and other commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt obligations. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control.

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:    

• selling assets;

• reducing or delaying capital investments;

• seeking to raise additional capital; or

• refinancing or restructuring our debt.

If for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable, which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements. In addition, our the trustee or noteholders of our Senior Secured Notes could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on our unsecured notes. If amounts outstanding under our secured and unsecured notes were to be accelerated, we cannot be certain that our assets would be sufficient to repay in full the money owed to the debt holders, or to holders of our 9.25% Series B Cumulative Preferred Stock. Please see “Part 1, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity.”

Recently approved final rules regulating air emissions from natural gas production operations could cause us to incur increased capital expenditures and operating costs, which may be significant.

On April 17, 2012, the EPA approved final regulations under the Clean Air Act that, among other things, require additional emissions controls for natural gas and natural gas liquids production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOC”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities. The final regulations require the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. We are currently reviewing this new rule and assessing its potential impacts. Compliance with these requirements could increase our

40

costs of development and production, although we do not expect these requirements to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

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

See our Current Reports on Form 8-K for sales of unregistered equity securities previously reported during the six months ended June 30, 2012.

ITEM 3. Defaults Upon Senior Securities.

None.

ITEM 4. Mine Safety Disclosures.

None.

ITEM 5. Other Information.

None.

ITEM 6. Exhibits.

See Exhibit Index, which is incorporated by reference herein.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		GMX RESOURCES INC.
Date:	August 8, 2012	/s/ James A. Merrill
		James A. Merrill
		Chief Financial Officer

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EXHIBIT INDEX

		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
3.1(a)	Amended and Restated Certificate of Incorporation of GMX Resources Inc.	SB-2	333-49328	3.1	11/6/2000
3.1(b)	Amended Certificate of Incorporation of GMX Resources Inc.	8-K	001-32977	3.1	5/25/2010
3.1(c)	Amended Certificate of Incorporation of GMX Resources Inc.	8-K	001-32977	3.1	5/17/2012
3.2	Amended and Restated Bylaws of GMX Resources Inc.	8-K	001-32977	3.2	11/4/2008
3.3	Certificate of Designation of Series A Junior Participating Preferred Stock of GMX Resources Inc.	8-K	000-32325	3.1	5/18/2005
3.4(a)	Certificate of Designation of 9.25% Series B Cumulative Preferred Stock	8-A12B	001-32977	4.1	8/8/2006
3.4(b)	Certificate of Amendment to the Certificate of Designation of the 9.25% Series B Cumulative Preferred Stock	8-K	011-32977	3.1	12/14/2010
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	5/18/2005
4.1(b)	Amendment No. 1 to Rights Agreement dated February 1, 2008	8-A/A	001-32977	2.1	2/21/2008
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	2/15/2008
4.3	Registration Rights Agreement dated February 11, 2008, between GMX Resources Inc. and Jefferies Funding LLC	8-K	001-32977	10.4	2/15/2008
4.4(a)	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(b)	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
4.5	Indenture dated February 9, 2011, between GMX Resources Inc. and the Bank of New York Mellon Trust Company, N.A., as Trustee	8-K	001-32977	4.1	2/9/2011
4.6	First Supplemental Indenture dated December 19, 2011, between GMX Resources Inc., the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as Trustee	8-K	011-32977	4.8	12/19/2011
4.7	Indenture dated December 19, 2011, between GMX Resources Inc., the Guarantors named therein and U.S. Bank, N.A., as Trustee	8-K	011-32977	4.1	12/21/2011
4.8	Form of Senior Secured Note due 2017 (included as Exhibit A)	8-K	011-32977	4.1	12/21/2011
4.9	Security Agreement, dated as of December 19, 2011 between GMX Resources Inc. and U.S. Bank National Association as Collateral Agent	8-K	011-32977	4.3	12/21/2011
4.10	Security Agreement, dated as of December 19, 2011 between Endeavor Pipeline Inc. and U.S. Bank National Association as Collateral Agent	8-K	011-32977	4.4	12/21/2011

43

		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
4.11	Security Agreement, dated as of December 19, 2011 between Diamond Blue Drilling Co. and U.S. Bank National Association as Collateral Agent	8-K	011-32977	4.5	12/21/2011
4.12	Registration Rights Agreement dated February 9, 2011, between GMX Resources Inc. and Credit Suisse Securities (USA) LLC and Morgan Stanley & Co. Incorporated	8-K	001-32977	4.3	2/9/2011
4.13	Registration Rights Agreement dated February 28, 2011 between GMX Resources Inc. and Retamco Operating, Inc.	8-K	001-32977	10.1	3/2/2011
4.14	Stockholder and Registration Rights Agreement, dated April 28, 2011, among GMX Resources Inc., Arkoma Bakken, LLC, Long Properties Trust and Reynolds Drilling Co., Inc.	8-K	001-32977	10.1	5/4/2011
4.15	Registration Rights Agreement dated as of December 19, 2011, by and among GMX Resources Inc., the Guarantors named therein and the Supporting Holders party thereto	8-K	001-32977	4.6	12/21/2011
4.16	Registration Rights Agreement dated as of December 19, 2011, by and among GMX Resources Inc., the Guarantors named therein and the Supporting Holders party thereto	8-K	001-32977	4.7	12/21/2011
12.1	Computation of Ratio of Earnings to Fixed Charges and to Combined Fixed Charges and Preference Dividends					*
31.1	Rule 13a-14(a) Certification of Chief Executive Officer					*
31.2	Rule 13a-14(a) Certification of Chief Financial Officer					*
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350					*
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350					*
101.INS	XBRL Instance Document					*
101.SCH	XBRL Taxonomy Extension Schema					*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase					*
101.DEF	XBRL Taxonomy Extension Definition Linkbase					*
101.LAB	XBRL Taxonomy Extension Label Linkbase					*
101.PRE	XBRL Taxonomy Extension Presentation Linkbase					*

44