Exhibit 99.1

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

Reports of Independent Registered Public Accounting Firms			F-2
Consolidated Balance Sheets, December 31, 2010 and 2009			F-4
Consolidated Statements of Operations, Years Ended December 31, 2010, 2009 and 2008			F-5
Consolidated Statements of Changes in Equity, Years Ended December 31, 2010, 2009 and 2008			F-6
Consolidated Statements of Comprehensive Income (Loss), Years Ended December 31, 2010, 2009, 2008			F-7
Consolidated Statements of Cash Flows, Years Ended December 31, 2010, 2009 and 2008			F-8
Notes to Consolidated Financial Statements			F-9

 

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

GMX Resources Inc.

We have audited the accompanying consolidated balance sheets of GMX Resources Inc. (an Oklahoma corporation) and Subsidiaries (collectively, the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, changes in equity, comprehensive income (loss) and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GMX Resources Inc. and Subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note A to the consolidated financial statements, the Company changed its method of estimating oil and gas reserves and related disclosures in 2009. Also, as discussed in Note B to the consolidated financial statements, the Company changed the manner in which it accounts for share lending arrangements, as of January 1, 2010, and retrospectively applied the effects of the adjustments to prior periods. We also have audited the adjustments to the 2008 consolidated financial statements to retrospectively apply the change in accounting for share lending arrangements, as described in Note B to the consolidated financial statements. We also have audited the adjustments to the 2008 consolidated financial statements to retrospectively apply the changes in accounting for convertible notes that may be settled in cash upon conversion, as described in Note C to the consolidated financial statements included in the Company’s 2009 Annual Report on Form 10-K (not included herein). In our opinion, such adjustments are appropriate and have been properly applied. We were not engaged to audit, review, or apply any procedures to the 2008 financial statements of the Company other than with respect to such adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2008 financial statements taken as a whole.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), GMX Resources Inc. and Subsidiaries’ internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 10, 2011, which is not included herein, expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

March 10, 2011

(except for Note P, which is as of November 1, 2011)

 

F-2

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and

Stockholders of GMX Resources Inc. and Subsidiaries

We have audited, before the effects of the adjustments, to retrospectively apply the change in accounting described in Note C (not presented herein) of the financial statements included in the Company’s 2009 Annual Report on Form 10-K and before the effects of the adjustments to retrospectively apply the change in accounting described in Note B (included herein), to the consolidated statements of operations, changes in equity, comprehensive income (loss), and cash flows of GMX Resources Inc. and Subsidiaries for the year ended December 31, 2008. (The 2008 financial statements before the effects of the aforementioned adjustments are not presented herein.) These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As described in Note B (not presented herein) of the financial statements included in the Company’s 2009 Annual Report on Form 10-K, the 2008 financial statements have been restated to correct a material misstatement relating to the method used to record the Company’s full cost pool impairment charges and related deferred taxes and the computation of the Company’s diluted loss per share.

In our opinion, the 2008 financial statements presented herein, before the effects of the adjustments to retrospectively apply the change in accounting described in Note C (not presented herein) to the financial statements included in the Company’s 2009 Annual Report on Form 10-K and before the effects of the adjustments to retrospectively apply the change in accounting described in Note B (included herein), present fairly, in all material respects, the results of operations and cash flows of GMX Resources Inc. and Subsidiaries as of December 31, 2008, in conformity with generally accepted accounting principles in the United States of America.

We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively apply the change in accounting described in Note C (not presented herein) of the financial statements included in the Company’s 2009 Annual Report on Form 10-K or to the adjustments to retrospectively apply the change in accounting described in Note B (included herein) and, accordingly, we do not express an opinion or any other form of assurance about whether such adjustments are appropriate and have been properly applied. Those adjustments were audited by Grant Thornton LLP.

/s/ Smith, Carney & Co., p.c.

Oklahoma City, Oklahoma

February 27, 2009, except for the

restatement described in Note B

(not presented herein) of the Company’s

2009 Annual Report on Form 10-K,

as to which the date is March 16, 2010,

except for Note P, which is dated

November 1, 2011

 

F-3

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GMX Resources Inc. and Subsidiaries

Consolidated Balance Sheets

(dollars in thousands, except share data)

 

		December 31,
		2010				2009
						(as adjusted)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	2,357			$	35,554
Accounts receivable—interest owners			5,339				1,233
Accounts receivable—oil and natural gas revenues, net			6,829				9,340
Derivative instruments			19,486				12,252
Inventories			326				326
Prepaid expenses and deposits			5,767				4,506
Assets held for sale			26,618				—
Total current assets			66,722				63,211
OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD
Properties being amortized			938,701				756,412
Properties not subject to amortization			39,694				39,789
Less accumulated depreciation, depletion, and impairment			(630,632	)			(464,872	)
			347,763				331,329
PROPERTY AND EQUIPMENT, AT COST, NET			69,037				101,755
DERIVATIVE INSTRUMENTS			17,484				17,292
OTHER ASSETS			6,084				8,484
TOTAL ASSETS		$	507,090			$	522,071
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable		$	24,919			$	19,180
Accrued expenses			33,048				12,907
Accrued interest			3,317				3,361
Revenue distributions payable			4,839				4,434
Current maturities of long-term debt			26				48
Total current liabilities			66,149				39,930
LONG-TERM DEBT, LESS CURRENT MATURITIES			284,943				190,230
DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS			10,622				16,299
OTHER LIABILITIES			7,157				7,151
COMMITMENTS AND CONTINGENCIES—SEE NOTE I
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, 2,041,169 and 2,000,000 shares issued and outstanding as of 2010 and 2009, respectively, (aggregate liquidation preference $50,000,000)			2				2
Common stock, par value $.001 per share—100,000,000 shares authorized, 31,283,353 issued and outstanding in 2010 and 31,214,968 shares in 2009			31				31
Additional paid-in capital			531,944				522,645
Accumulated deficit			(430,784	)			(284,745	)
Accumulated other comprehensive income, net of taxes			15,227				8,447
Total GMX equity			116,420				246,380
Noncontrolling interest			21,799				22,081
Total equity			138,219				268,461
TOTAL LIABILITIES AND EQUITY		$	507,090			$	522,071

See accompanying notes to consolidated financial statements.

 

F-4

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GMX Resources Inc. and Subsidiaries

Consolidated Statements of Operations

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

 

		Year Ended December 31,
		2010				2009				2008
						(as adjusted)				(as adjusted)
OIL AND GAS SALES, net of gain or (loss) from ineffectiveness of derivatives of $(1,280) $1,018 and $1,014, respectively		$	96,523			$	94,294			$	125,736
EXPENSES:
Lease operations			10,651				11,776				15,101
Production and severance taxes			743				(930	)			5,306
Depreciation, depletion, and amortization			38,061				31,006				31,744
Impairment of oil and natural gas properties and assets held for sale			143,712				188,150				192,650
General and administrative			27,119				21,390				16,899
Total expenses			220,286				251,392				261,700
Loss from operations			(123,763	)			(157,098	)			(135,964	)
NON-OPERATING INCOME (EXPENSES):
Interest expense			(18,642	)			(16,748	)			(14,105	)
Loss on extinguishment of debt			—				(4,976	)			—
Interest and other income (expense)			(4	)			72				285
Unrealized loss on derivatives			(122	)			(2,370	)			(354	)
Total non-operating expenses			(18,768	)			(24,022	)			(14,174	)
Loss before income taxes			(142,531	)			(181,120	)			(150,138	)
BENEFIT FOR INCOME TAXES			4,239				33				26,217
NET LOSS			(138,292	)			(181,087	)			(123,921	)
Net income attributable to noncontrolling interest			3,114				173				—
NET LOSS APPLICABLE TO GMX			(141,406	)			(181,260	)			(123,921	)
Preferred stock dividends			4,633				4,625				4,625
NET LOSS APPLICABLE TO COMMON SHAREHOLDERS		$	(146,039	)		$	(185,885	)		$	(128,546	)
LOSS PER SHARE—Basic		$	(5.18	)		$	(9.20	)		$	(9.04	)
LOSS PER SHARE—Diluted		$	(5.18	)		$	(9.20	)		$	(9.04	)
WEIGHTED AVERAGE COMMON SHARES—Basic			28,206,506				20,210,400				14,216,466
WEIGHTED AVERAGE COMMON SHARES—Diluted			28,206,506				20,210,400				14,216,466

See accompanying notes to consolidated financial statements.

 

F-5

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GMX Resources Inc. and Subsidiaries

Consolidated Statement of Changes in Equity

Year Ended December 31, 2008, 2009 and 2010

(dollars and shares in thousands)

 

		Preferred shares				Common shares				Preferred par value				Common par value				Additional paid-in capital				Retained earnings (accumulated deficit)				Accumulated other comprehensive income				Total GMX Resources equity				Non- controlling interest				Total equity
BALANCE AT DECEMBER 31, 2007			2,000				13,268			$	2			$	13			$	180,543			$	29,686			$	(1,318	)		$	208,926			$	—			$	208,926
Stock Options Exercised			—				73				—				—				979				—				—				979				—				979
Restricted Stock Awards			—				14				—				—				—				—				—				—				—				—
Stock Compensation Expense			—				—				—				—				3,545				—				—				3,545				—				3,545
Preferred Stock Dividends			—				—				—				—				—				(4,625	)			—				(4,625	)			—				(4,625	)
Shares Issued			—				2,000				—				2				133,685				—				—				133,687				—				133,687
Shares Pursuant to Share Lending Agreement (as adjusted)			—				3,440				—				4				2,338				—				—				2,342				—				2,342
Convertible Debt Issued			—				—				—				—				9,250				—				—				9,250				—				9,250
Net Loss (as adjusted)			—				—				—				—				—				(123,921	)			—				(123,921	)			—				(123,921	)
Other Comprehensive Income			—				—				—				—				—				—				16,614				16,614				—				16,614
BALANCE AT DECEMBER 31, 2008 (as adjusted)			2,000				18,795			$	2			$	19			$	330,340			$	(98,860	)		$	15,296			$	246,797			$	—			$	246,797
Stock Options Exercised			—				1				—				—				5				—				—				5				—				5
Restricted Stock Awards			—				19				—				—				—				—				—				—				—				—
Stock Compensation Expense			—				—				—				—				5,844				—				—				5,844				—				5,844
Preferred Stock Dividends			—				—				—				—				—				(4,625	)			—				(4,625	)			—				(4,625	)
Shares Issued			—				12,700				—				13				164,051				—				—				164,064				—				164,064
Shares Pursuant to Share Lending Agreement			—				(300	)			—				(1	)			—				—				—				(1	)			—				(1	)
Convertible Debt Issued			—				—				—				—				8,421				—				—				8,421				—				8,421
Sale of Subsidiary Membership Interest to Noncontrolling Interest			—				—				—				—				13,984				—				—				13,984				21,908				35,892
Net Loss (as adjusted)			—				—				—				—				—				(181,260	)			—				(181,260	)			173				(181,087	)
Other Comprehensive Loss			—				—				—				—				—				—				(6,849	)			(6,849	)			—				(6,849	)
BALANCE AT DECEMBER 31, 2009 (as adjusted)			2,000				31,215			$	2			$	31			$	522,645			$	(284,745	)		$	8,447			$	246,380			$	22,081			$	268,461
Restricted Stock Awards			—				188				—				—				—				—				—				—				—				—
Preferred Stock Dividends			—				—				—				—				—				(4,633	)			—				(4,633	)			—				(4,633	)
Stock Compensation Expense			—				—				—				—				6,274				—				—				6,274				—				6,274
Shares Issued			41				380				—				—				3,025				—				—				3,025				—				3,025
Shares Pursuant to Share Lending Agreement			—				(500	)			—				—				—				—				—				—				—				—
Net Loss			—				—				—				—				—				(141,406	)			—				(141,406	)			3,114				(138,292	)
Contributions—Non-Controlling Interest			—				—				—				—				—				—				—				—				1,244				1,244
Distributions—Non-Controlling Interest			—				—				—				—				—				—				—				—				(4,640	)			(4,640	)
Other Comprehensive Income			—				—				—				—				—				—				6,780				6,780				—				6,780
BALANCE AT DECEMBER 31, 2010			2,041				31,283			$	2			$	31			$	531,944			$	(430,784	)		$	15,227			$	116,420			$	21,799			$	138,219

See accompanying notes to consolidated financial statements.

 

F-6

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GMX Resources Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (Loss)

(dollars in thousands)

 

		Years Ended December 31,
		2010				2009				2008
						(as adjusted)				(as adjusted)
Net loss		$	(138,292	)		$	(181,087	)		$	(123,921	)
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative instruments, net of income taxes of $11,512, $6,961 and $6,499, respectively			22,346				13,513				12,615
Reclassification of (gain) loss on settled contracts, net of income taxes of ($8,019), ($10,489) and $2,060, respectively			(15,566	)			(20,362	)			3,999
Comprehensive loss			(131,512	)			(187,936	)			(107,307	)
Comprehensive income attributable to the noncontrolling interest			3,114				173				—
Comprehensive loss attributable to GMX shareholders		$	(134,626	)		$	(188,109	)		$	(107,307	)

 

 

 

See accompanying notes to consolidated financial statements.

 

F-7

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GMX Resources Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(dollars in thousands)

 

		Year Ended December 31,
		2010				2009				2008
						(as adjusted)				(as adjusted)
CASH FLOWS DUE TO OPERATING ACTIVITIES
Net loss		$	(138,292	)		$	(181,087	)		$	(123,921	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization			38,061				31,006				31,744
Impairment and other writedowns			143,712				188,150				192,650
Deferred income taxes			(4,209	)			—				(26,243	)
Non-cash stock compensation expense			5,450				4,635				3,085
Loss (gain) on extinguishment of debt			(141	)			4,976				—
Non-cash interest expense			9,330				6,036				2,159
Other			1,402				1,838				(1,151	)
Decrease (increase) in:
Accounts receivable			(1,595	)			(1,338	)			717
Prepaid expenses and other assets			(1,730	)			(457	)			(1,089	)
Increase (decrease) in:
Accounts payable and accrued expenses			6,680				(2,852	)			3,558
Revenue distributions payable			67				(1,417	)			1,728
Net cash provided by operating activities			58,735				49,490				83,237
CASH FLOWS DUE TO INVESTING ACTIVITIES
Purchase of oil and natural gas properties			(172,726	)			(162,076	)			(281,447	)
Proceeds from sales of oil and natural gas properties			5,522				—				—
Purchase of property and equipment			(10,284	)			(19,248	)			(36,913	)
Proceeds from sale of property and equipment			1,488				—				—
Net cash used in investing activities			(176,000	)			(181,324	)			(318,360	)
CASH FLOWS DUE TO FINANCING ACTIVITIES
Advance on revolving bank credit facility			92,000				99,000				190,000
Payments on debt			(79	)			(179,079	)			(204,210	)
Proceeds from sale of common stock			—				164,069				134,681
Proceeds from sale of preferred stock			949				—				—
Issuance of 5.00% Convertible Senior Notes			—				—				125,000
Issuance of 4.50% Convertible Senior Notes			—				86,250				—
Dividends paid on Series B cumulative preferred stock			(4,633	)			(4,625	)			(4,625	)
Proceeds from (repayment of) Senior Secured Notes			—				(34,590	)			—
Sale of equity interest of a business			—				36,000				—
Contributions from non-controlling interest member			1,244				—				—
Distributions to non-controlling interest member			(4,640	)			—				—
Fees paid related to financing activities			(773	)			(7,085	)			(4,914	)
Other			—				732				—
Net cash provided by financing activities			84,068				160,672				235,932
NET INCREASE (DECREASE) IN CASH			(33,197	)			28,838				809
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD			35,554				6,716				5,907
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	2,357			$	35,554			$	6,716
SUPPLEMENTAL CASH FLOW DISCLOSURE CASH PAID (RECEIVED) DURING THE PERIOD FOR:
INTEREST, NET OF AMOUNTS CAPITALIZED		$	11,988			$	15,611			$	10,343
INCOME TAXES		$	(30	)		$	(33	)		$	26

See accompanying notes to consolidated financial statements.

 

F-8

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GMX Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements

December 31, 2010, 2009 and 2008

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

NATURE OF BUSINESS AND PRINCIPLES OF CONSOLIDATION

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

During 2010, we made a strategic decision to pursue properties that would expand our assets and development into other basins, diversify our company’s concentrated natural gas focus from two resource plays in one basin and provide the company more liquid hydrocarbon opportunities. These efforts have led to successful agreements to acquire core positions in over 67,000 net acres in two of the leading oil resource plays in the U.S. We have recently in 2011 entered into separate agreements to purchase undeveloped leasehold in the very successful and competitive region located in the Williston Basin of North Dakota/Montana, targeting the Bakken/Sanish-Three Forks Formation, and in the oil window of the Denver Julesburg Basin (the “DJ Basin”) of Wyoming, targeting the emerging Niobrara Formation. We are making plans to deploy our capital and resources into these development opportunities in 2011. With the acquisition of the liquids-rich (estimated 90% oil) Bakken and Niobrara acreage, we will have better flexibility to deploy capital based on a variety of economic and technical factors, including well costs, service availability, take-away capacity and commodity prices (including differentials applicable to the basin). We believe this flexibility will enable us to generate better cash flow growth to fund our capital expenditure program. We believe our contracted FlexRigs and experienced Rockies and Haynesville/Bossier Shale horizontal drilling personnel will enable us to succeed in the development of these new oil resource plays.

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

The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States (“GAAP”). References to GAAP issued by the Financial Accounting Standards Board (“FASB”) in these footnotes are to the FASB Accounting Standards Codification (“ASC”). The consolidated financial statements include the accounts of GMX and its wholly and majority owned subsidiaries. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. All significant intercompany transactions have been eliminated.

USE OF ESTIMATES: The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include estimates for proved oil and natural gas reserve quantities, deferred income taxes, asset retirement obligations, fair value of derivative instruments, useful lives of property and equipment, expected volatility and contract term to exercise outstanding stock options, and are subject to change.

 

F-9

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RECLASSIFICATIONS: Certain reclassifications in the Consolidated Statements of Cash Flows have been made to prior years amounts to conform to current year presentations.

CASH AND CASH EQUIVALENTS: The Company considers all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.

CONCENTRATIONS OF CREDIT RISK: Substantially all of the Company’s receivables are within the oil and gas industry, primarily from purchasers of natural gas and crude oil and from partners with interests in common properties operated by the Company. Although diversified among many companies, collectability is dependent upon the financial wherewithal of each individual company as well as the general economic conditions of the industry. The receivables are not collateralized; however the Company does review these parties for creditworthiness and general financial condition.

The Company has accounts with separate banks in Louisiana and Oklahoma. At December 31, 2010 and 2009, the Company had $4.5 million and $32.3 million, respectively, invested in overnight investment sweep accounts. Bank deposit accounts may, at times, exceed federally insured limits. The Company has not experienced any losses in such accounts and does not believe it is exposed to significant credit risk on its cash. The difference between the investment amount and the cash and cash equivalents amount on the accompanying consolidated balance sheets represents uncleared disbursements and non-interest bearing checking accounts.

The Company currently uses natural gas and crude oil commodity derivatives to hedge a portion of its exposure to natural gas and crude oil price volatility. These arrangements expose the Company to credit risk from its counterparties. To mitigate that risk, the Company only uses counterparties that are highly-rated entities with corporate credit ratings at or exceeding A or Aa as classified by Standard & Poor’s and Moody’s, respectively.

Sales to individual customers constituting 10% or more of total natural gas and crude oil sales were as follows for each of the years ended December 31:

 

		2010				2009				2008
Natural gas
Texla Energy Management, Inc.			44	%			54	%			20	%
Tenaska			16	%			—				—
Various purchasers through Penn Virginia Oil & Gas, L.P.			14	%			21	%			42	%
Louis Dreyfus			10	%			—				—
BP Energy Company			—				12	%			—
Waskom Gas Processing Company			—				11	%			10	%
CrossTex Energy Services, Inc.			—				—				22	%
Crude oil
Sunoco, Inc			61	%			52	%			14	%
Various purchasers through Penn Virginia Oil & Gas, L.P.			39	%			43	%			54	%
Teppco Crude Oil, LLC			—				—				14	%
SemCrude, L.P.			—				—				17	%

If the Company were to lose a purchaser, it believes it could replace it with a substitute purchaser with substantially equivalent terms.

INVENTORIES: Inventories consist of crude oil in tanks and natural gas liquids. Treated and stored crude oil inventory and natural gas liquids at the end of the year are valued at the lower of production cost or market.

ACCOUNTS RECEIVABLE: The Company has receivables from joint interest owners and oil and gas purchasers that are generally uncollateralized. The Company reviews these parties for creditworthiness and general financial condition. Accounts receivable are generally due within 30 days and accounts outstanding

 

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longer than 60 days are considered past due. If necessary, the Company would determine an allowance by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and gas properties operated by the Company and the owners ability to pay its obligation, among other things. The Company writes off accounts receivable when they are determined to be uncollectible.

The Company establishes provisions for losses on accounts receivable if it determines that it will not collect all or part of the outstanding balance. The Company regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. There was no allowance for doubtful accounts at December 31, 2010 and 2009.

OIL AND NATURAL GAS PROPERTIES: The Company follows the full cost method of accounting for its oil and natural gas properties and activities. Accordingly, the Company capitalizes all costs incurred in connection with the acquisition, exploration and development of oil and natural gas properties. The Company capitalizes internal costs that can be directly identified with exploration and development activities, but does not include any costs related to production, general corporate overhead, or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and gas wells, including salaries and benefits and other internal costs directly attributable to these activities. Also included in oil and natural gas properties are tubular and other lease and well equipment of $4.1 million and $32.2 million at December 31, 2010 and 2009, respectively, that have not been placed in service but for which we plan to utilize in our on-going exploration and development activities.

Proceeds from dispositions of oil and gas properties are accounted for as a reduction of capitalized costs, with no gain or loss generally recognized upon disposal of oil and natural gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. Revenues from services provided to working interest owners of properties in which GMX also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties.

Investments in unevaluated properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. The balance of unevaluated properties is comprised of capital costs incurred for undeveloped acreage, exploratory wells in progress and capitalized interest costs. We assess all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. We assess our properties on an individual basis or as a group if properties are individually insignificant. Our assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full-cost pool and are then subject to amortization.

Depreciation, depletion and amortization of oil and gas properties (“DD&A”) are provided using the units-of-production method based on estimates of proved oil and gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. The Company’s cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs and the anticipated proceeds from salvaging equipment. DD&A expense for oil and natural gas properties was $32.9 million, $23.9 million and $26.9 million for the years ended December 31, 2010, 2009, and 2008, respectively.

Capitalized costs are subject to a “ceiling test,” which limits the net book value of oil and natural gas properties less related deferred income taxes to the estimated after-tax future net revenues discounted at a 10-percent interest rate. The cost of unproved properties is added to the future net revenues less income tax effects. At December 31, 2010 and 2009, future net revenues are calculated using prices that represent the average of the first day of the month price for the 12-month period prior to the end of the period.

 

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Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. Based on average prices for the prior 12-month period for natural gas and oil as of December 31, 2010 and 2009, these cash flow hedges increased the full-cost ceiling by $52.3 million and $69.7 million, respectively, thereby reducing the ceiling test write-down by the same amount. Our qualifying cash flow hedges as of December 31, 2010, which consisted of swaps and collars, covered 19.6 Bcf and 18.5 Bcf in 2011and 2012, respectively. Our natural gas and oil hedging activities are discussed in “Note E—Derivative Activities,” of these consolidated financial statements.

Two primary factors impacting the ceiling test are reserve levels and natural gas and oil prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. As a result of the Company’s ceiling test as of December 31, 2010, 2009 and 2008, the Company recorded impairment expense of $132.8 million, $188.2 million, and $192.7 million, respectively.

PROPERTY AND EQUIPMENT: Property and equipment are capitalized and stated at cost, while maintenance and repairs are expensed currently. Depreciation and amortization of other property and equipment are provided when assets are placed in service using the straight-line method based on estimated useful lives ranging from three to twenty years. In 2009, we changed the estimated useful life of the pipeline assets from 10 to 20 years. Depreciation and amortization expense for property and equipment was $5.1 million, $7.1 million and $4.8 million for the years ending December 31, 2010, 2009, and 2008, respectively.

IMPAIRMENT OF LONG-LIVED ASSETS: Pipeline and gathering system assets and other long-lived assets used in operations are periodically assessed to determine if circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. The Company had no such impairment losses for the years ended December 31, 2010, 2009 or 2008.

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. As a result of determining fair value, an impairment loss was recorded for the year ended December 31, 2010 on the assets held for sale in the amount of $9.6 million and selling costs were estimated to be $1.3 million, resulting in a total write-down of $10.9 million.

DEBT ISSUE COSTS: The Company amortizes debt issue costs related to its revolving bank credit facility, 5.00% Convertible Senior Notes and 4.50% Convertible Senior Notes as interest expense over the scheduled maturity period of the debt. Unamortized debt issue costs were approximately $9.1 million and $8.6 million as of December 31, 2010 and 2009, respectively. The Company includes those unamortized costs in current prepaid expenses and deposits and other assets.

REVENUE DISTRIBUTIONS PAYABLE: For certain oil and natural gas properties, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds applicable to other revenue and royalty owners are reflected as revenue distributions payable in the accompanying balance sheets. We recognize revenue for only our net interest in oil and natural gas properties.

DEFERRED INCOME TAXES: Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or

 

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liabilities are determined by applying the presently enacted tax rates and laws. The Company records a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets will not be realized.

The Company recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in accrued expenses and other current liabilities. As of December 31, 2010 and 2009, the Company had no such liabilities.

REVENUE RECOGNITION: Natural gas and crude oil revenues are recognized when sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a purchaser’s pipeline or truck. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, the Company makes accruals for revenues and accounts receivable based on estimates of its share of production, particularly from properties that are operated by others. Since the settlement process may take 30 to 60 days following the month of actual production, the Company’s financial results include estimates of production and revenues for the related time period. The Company records any differences, which are not expected to be significant, between the actual amounts ultimately received and the original estimates in the period they become finalized.

NATURAL GAS BALANCING: During the course of normal operations, the Company and other joint interest owners of natural gas reservoirs will take more or less than their respective ownership share of the natural gas volumes produced. These volumetric imbalances are monitored over the lives of the wells’ production capability. If an imbalance exists at the time the wells’ reserves are depleted, cash settlements are made among the joint interest owners under a variety of arrangements. The Company follows the sales method of accounting for gas imbalances. A liability is recorded when the Company’s natural gas volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production. There are no significant imbalances as of December 31, 2010 or 2009.

PRODUCTION AND SEVERANCE TAXES: Production taxes are set by state and local governments and vary as to the tax rate and the value to which that rate is applied. In Texas, where substantially all of our production is derived, severance taxes are levied as a percent of revenue received. The rate in Texas is complicated by certain severance tax exemptions or rate deductions on high cost wells. Certain wells, including all of our H/B wells, qualify for full severance tax relief for a period of ten years or recovery of 50% of the cost of drilling and completions, whichever is less. As a result, refunds for severance tax paid to the State of Texas on wells that qualify for reimbursement are recognized as accounts receivable and offset severance tax expense for the amount refundable as of December 31, 2010 (net of filing fees paid to a third party). As of December 31, 2009 and 2008 credits were not recognized until approvals are received. Production and severance taxes for the years ended December 31, 2010, 2009 and 2008 reflect tax refunds received and accrued of $3.1 million, $2.9 million and $1.2 million, respectively.

DERIVATIVE INSTRUMENTS: The Company uses derivative financial instruments to manage its exposure to lower oil and natural gas prices. Derivative instruments are measured at fair value and recognized as assets or liabilities in the balance sheet. Upon entering into a derivative contract, the derivative may be designated as a cash flow hedge. The relationship between the derivative instrument designated as a hedge and the hedged items is documented, as well as our objective for risk management and strategy for use of the hedging instrument to manage the risk. Derivative instruments designated as cash flow hedges are linked to specific

 

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forecasted transactions. At inception, and on an ongoing basis, a derivative instrument used as a hedge is assessed as to whether it is highly effective in offsetting changes in the cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting.

Changes in fair value of a qualifying cash flow hedge are recorded in accumulated other comprehensive income, until earnings are affected by the cash flows of the hedged item. When the cash flow of the hedged item is recognized in the statement of operations, the fair value of the associated cash flow hedge is reclassified from accumulated other comprehensive income into earnings as a component of oil and gas sales. Ineffective portions of a cash flow hedge are recognized currently in earnings as a component of oil and gas sales. The changes in fair value of derivative instruments not qualifying or not designated as hedges are reported currently in the consolidated statement of operations as unrealized gains (losses) on derivatives, a component of non-operating income (expense). If a derivative instrument no longer qualifies as a cash flow hedge, hedge accounting is discontinued and the gain or loss that was recorded in accumulated other comprehensive income is recognized over the period anticipated in the original hedge transaction.

FAIR VALUE. Fair value is defined as the price that would be received to sell an asset or price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair-value-measurement hierarchy are as follows:

Level 1—inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).

Level 2—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).

Level 3—inputs that are not observable from objective sources, such as the Company’s internally developed assumptions used in pricing an asset or liability.

In determining fair value, the Company utilizes observable market data when available, or models that incorporate observable market data. In addition to market information, the Company incorporates transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. In arriving at fair-value estimates, the Company utilizes the most observable inputs available for the valuation technique employed. If a fair-value measurement reflects inputs at multiple levels within the hierarchy, the fair-value measurement is characterized based upon the lowest level of input that is significant to the fair-value measurement. Recurring fair-value measurements are performed for derivatives instruments. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable and deferred premiums on derivative instruments reported on the balance sheet approximates fair value.

ASSET RETIREMENT OBLIGATIONS: The Company’s asset retirement obligations relate to estimated future plugging and abandonment expenses on its oil and gas properties and related facilities disposal. These obligations to abandon and restore properties are based upon estimated future costs that may change based upon future inflation rates and changes in statutory remediation rules. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and gas properties.

ENVIRONMENTAL LIABILITIES: Environmental expenditures that relate to an existing condition caused by past operation and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2010 and 2009, the Company has not accrued for or been fined or cited for any

 

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environmental violations that would have a material adverse effect upon the financial position, operating results or the cash flows of the Company.

BASIC EARNINGS PER SHARE AND DILUTED EARNINGS PER SHARE: Basic net income 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 net income per common share is calculated in the same manner, but also considers the impact to net income and common shares for the potential dilution from our convertible notes, outstanding stock options and non-vested restricted stock awards. The following table reconciles the weighted average shares outstanding used for these computations for the years ending December 31:

 

		2010				2009				2008
Weighted average shares outstanding—basic			28,206,506				20,210,400				14,216,466
Effective of dilutive securities:
Stock options			—				—				—
Weighted average shares outstanding—diluted			28,206,506				20,210,400				14,216,466

Common shares outstanding loaned in connection with the 5.00% Convertible Senior Notes issued in February 2008 in the amount of 2,640,000 and 3,140,000 shares were not included in the computation of earnings per common share for the years ending December 31, 2010 or 2009, respectively.

For purposes of calculating weighted average common shares—diluted, non-vested restricted stock and outstanding stock options would be included in the computation using the treasury stock method, with the proceeds equal to the amount of cash received from the employee upon exercise and the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity.

Due to our net loss from operations for the years ended December 31, 2010, 2009 and 2008, we excluded the effects of the convertible notes, stock options and shares of non-vested restricted stock as they would have been antidilutive. The amount of shares excluded for 2010, 2009 and 2008 was 66,061, 794,000 and 995,000, respectively.

STOCK BASED COMPENSATION: The Company recognizes compensation expense for all stock-based payment awards made to employees, contractors and non-employee directors. Stock-based compensation expense is measured at the grant date based on the fair value of the award and is recognized as expense over the requisite service period, which is generally the vesting period. For stock options, the Company uses the Black-Scholes option-pricing model to determine the option fair value, which requires the input of highly subjective assumptions, including the expected volatility of the underlying stock, the expected term of the award, the risk-free interest rate and expected future divided payments. Expected volatilities are based on our historical volatility. The expected life of an award is estimated using historical exercise behavior data and estimated future behavior. The risk-free interest rate is based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the expected life of the award. The Company does not expect to declare or pay dividends in the foreseeable future.

COMMITMENTS AND CONTINGENCIES: Liabilities for loss contingencies arising from claims, assessments, litigation, or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES: During the years ended December 31, 2010, 2009 and 2008, the Company recorded non-cash additions to oil and gas properties of $1.0 million, $1.2 million and $3.6 million, respectively related to the depreciation of its

 

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Company-owned rigs and the capitalization of non-cash stock compensation expense related to employees directly involved in exploration and development activities.

Capital additions funded through accounts payable include $14.6 million, $25.6 million, and $34.6 million for the years ended December 31, 2010, 2009, and 2008, respectively.

During the years ended December 31, 2010, 2009 and 2008, the Company recorded a net non-cash asset and related liability of $0.7 million, $0.6 million, and $2.4 million respectively, associated with the asset retirement obligation on the acquisition and/or development of oil and gas properties.

Interest of $2.6 million, $1.8 million, and $0.4 million, was capitalized during the years ended December 31, 2010, 2009, and 2008, respectively, related to the unproved properties that were not being currently depreciated, depleted or amortized and on which exploration or development activities were in progress.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS:

In December 2009, the Company adopted revised oil and gas reserve estimation and disclosure requirements. The primary impact of the new disclosures for the Company is to align the definition of proved reserves with the Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008 and effective for fiscal periods ending on or after December 31, 2009. The accounting standards revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period preceding the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technology to estimate proved oil and gas reserves, if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. The unaudited supplemental information on oil and gas exploration and production activities for 2010 and 2009 has been presented following these new reserve estimation and disclosure rules, which may not be applied retrospectively. The 2008 data is presented in accordance with the previous oil and gas disclosure requirements. See “Note M—Supplemental Information on Oil and Natural Gas Properties” for additional disclosures associated with the adoption of this standard.

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

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

 

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

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

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

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

 

•

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

 

•

the Company and the Share Borrower agree to terminate the Share Lending Agreement;

 

•

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

 

•

the Share Borrower elects to terminate all outstanding loans upon the bankruptcy of the Company.

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

 

•

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

 

•

to pay to the Company an amount equal to any cash dividends that are paid on the borrowed shares.

On January 1, 2010, the Company was required to adopt ASU 2009-15, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing, which changes the accounting treatment of the Company’s share lending arrangements. Under ASU 2009-15, the Company must recognize the value of share lending arrangements as issuance cost at inception.

 

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

 

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

The following financial statement line items in the consolidated statement of operations for the year ended December 31, 2009 and 2008, respectively, were affected by the adoption:

 

		Year ended December 31, 2009
		As Reported				Adjustments				As Adjusted
		(in thousands)
NON-OPERATING INCOME (EXPENSES)
Interest expense		$	(16,127	)		$	(621	)		$	(16,748	)
NET LOSS		$	(180,466	)		$	(621	)		$	(181,087	)
NET LOSS APPLICABLE TO COMMON SHAREHOLDERS		$	(185,264	)		$	(621	)		$	(185,885	)
EARNINGS (LOSS) PER SHARE—BASIC		$	(9.17	)		$	(.03	)		$	(9.20	)
EARNINGS (LOSS) PER SHARE—DILUTED		$	(9.17	)		$	(.03	)		$	(9.20	)
		Year ended December 31, 2008
		As Reported				Adjustments				As Adjusted
		(in thousands)
NON-OPERATING INCOME (EXPENSES)
Interest expense		$	(13,617	)		$	(488	)		$	(14,105	)
BENEFIT FOR INCOME TAXES		$	25,013			$	1,204			$	26,217
NET LOSS		$	(124,637	)		$	716			$	(123,921	)
NET LOSS APPLICABLE TO COMMON SHAREHOLDERS		$	(129,262	)		$	716			$	(128,546	)
EARNINGS (LOSS) PER SHARE—BASIC		$	(9.09	)		$	.05			$	(9.04	)
EARNINGS (LOSS) PER SHARE—DILUTED		$	(9.09	)		$	.05			$	(9.04	)

As of December 31, 2010 and 2009, respectively, 2,640,000 and 3,140,000, shares of our common stock were subject to outstanding loans to the Share Borrower with a fair value of $14.6 million and $43.1 million. As of December 31, 2010 and 2009, respectively, the unamortized amount of issuance costs associated with the share lending agreement was $1.7 million and $2.4 million, of which $0.8 million and $0.7 million is classified as a current asset and $0.9 million and $1.7 million, is a long-term asset included in Other Assets. The Company recognized $0.7 million, $0.6 million and $0.5 million in interest expense relating to the amortization of the Share Lending Agreement for the year ended December 31, 2010, 2009 and 2008 respectively

NOTE C—NONCONTROLLING INTEREST

On November 1, 2009, GMX and its wholly owned subsidiary, Endeavor Pipeline, transferred mid-stream gas gathering, compression and related equipment to a newly formed Endeavor Gathering and sold a 40% membership interest in Endeavor Gathering to KME for $36.0 million. Endeavor Gathering provides firm capacity gathering services to the Company in our Cotton Valley Sands and Haynesville/Bossier Shale horizontal

 

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developments in East Texas, and will also provide funding of future gathering infrastructure needs to support the Company’s production growth. The results of operations and financial position of Endeavor Gathering are included in the consolidated financial statements of GMX. The portion of Endeavor Gathering’s results of operations not attributable to GMX are recorded as noncontrolling interests.

Distributions to the members will be made on a monthly basis to the members and allocated 80% and 20% to the noncontrolling interest and to GMX, respectively until the noncontrolling interest member has received $36.0 million. Subsequently, distributions will be allocated 40% and 60% to the noncontrolling interest member and GMX, respectively.

The following table sets forth the effects of changes in GMX’s ownership interest in Endeavor Gathering on GMX’s equity for the years ended December 31:

 

		2010				2009 (as adjusted)				2008 (as adjusted)
		(in thousands)
Net loss applicable to GMX		$	(141,406	)		$	(181,260	)		$	(123,921	)
Transfers from the noncontrolling interest:
Increase in GMX paid-in capital for sale of 40% membership interest in Endeavor Gathering		$	—			$	13,984				—
Change from net loss applicable to GMX and transfers from noncontrolling interest		$	(141,406	)		$	(167,276	)		$	(123,921	)

NOTE D—PROPERTY AND EQUIPMENT

Major classes of property and equipment included the following at December 31:

 

		December 31,
		2010				2009
		(in thousands)
Pipeline and related facilities		$	57,798			$	68,440
Drilling rigs			—				30,492
Machinery and equipment			5,576				5,173
Buildings and leasehold improvement			8,418				6,003
Office equipment			4,619				2,324
			76,411				112,432
Less accumulated depreciation and amortization			(9,455	)			(12,751	)
			66,956				99,681
Land			2,081				2,074
		$	69,037			$	101,755

In December 2010, the Company finalized a plan to dispose of three drilling rigs, four compressors, pipe and valves by sale. These assets will either be disposed of individually or as part of a disposal group, depending on the purchaser’s interest. The accounting for these assets at the plan date was in accordance with ASC 360-10, Property, Plant and Equipment. Under this guidance, the assets 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 determining fair value for the drilling rigs, management used third party appraisals. For all other assets, management performed internal estimates of the value of the assets based on verbal bids gathered through their marketing efforts and other marketing information. Management also performed internal estimates to estimate the cost to sell the assets,

 

F-19

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which primarily consisted of commissions to sell the assets, and were estimated based on past experience selling similar assets and verbal bids. As a result of determining fair value, an impairment loss was recorded on the assets held for sale in the amount of $9.6 million and selling costs were estimated to be $1.3 million, resulting in a total write-down of $10.9 million, which was included in the Impairment of Oil and Natural Gas Properties and Assets Held for Sale in the Statements of Operations for the year ended December 31, 2010.

NOTE E—DERIVATIVE ACTIVITIES

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

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

The Company’s revolving bank credit facility requires it to maintain a hedging program on mutually acceptable terms whenever the loan amount outstanding exceeds 75% of the borrowing base.

The Company’s derivative financial instruments potentially consist of price swaps, collars, put spreads and basis swaps. A description of these types of instruments is provided below:

 

Fixed price swaps		The Company receives a fixed price and pays a variable price to the contract counterparty. The fixed-price payment and the floating price payment are netted, resulting in a net amount due to or from the counterparty.
Costless collars		The instrument contains a fixed floor price (long put option) and ceiling price (short call option), where the purchase price of the put option equals the sales price of the call option. At settlement, if the market price exceeds the ceiling price, the Company pays the difference between the market price and the ceiling price. If the market price is less than the fixed floor price, the Company receives the difference between the fixed floor price and the market price. If the market price is between the ceiling and the fixed floor price, no payments are due from either party.
Three-way collars		A three-way collar contract consists of a standard collar contract plus a put sold by the Company with a price below the floor price of the collar. This additional put requires us to make a payment to the counterparty if the settlement price for any settlement period is below the put price. Combining the collar contract with the additional put results in the Company being entitled to a net payment equal to the difference between the floor price of the standard collar and the additional put price if the settlement price is equal to or less than the additional put price. If the

 

F-20

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		settlement price is greater than the additional put price, the result is the same as it would have been with a standard collar contract only. Therefore, if market prices are below the additional put option, the Company would be entitled to receive the market price plus the difference between the additional put option and the floor. This strategy enables the Company to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar while defraying the associated cost with the sale of the additional put.
Put spreads		A put spread is the same as a three-way collar without the ceiling price (short call option). Therefore, if market prices are below the additional put option, the Company would be entitled to receive the market price plus the difference between the additional put option and the floor.
Basis swaps		Natural gas basis protection swaps are arrangements that guarantee a price differential between NYMEX natural gas futures and Houston Ship Channel or Mainline (Columbia Gulf), which is a close proximity for the Company’s primary market hubs. The Company receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.

The Company utilizes counterparties for our derivative instruments that are members of our lending bank group and that the Company believes are credit-worthy entities at the time the transactions are entered into. The Company closely monitors the credit ratings of these counterparties. Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. However, the recent events in the financial markets demonstrate there can be no assurance that a counterparty financial institution will be able to meet its obligations to the Company.

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.

ASC 815, Derivatives and Hedging requires all derivative instruments to be recognized at fair value in the balance sheet. Fair value is generally determined based on the difference between the fixed contract price and the underlying estimated market price at the determination date. Derivative instruments with the same counterparty are presented on a net basis where the legal right of offset exists. The following is a summary of the asset and liability fair values of the Company’s derivative contracts:

 

		Balance Sheet Location		Asset Fair Value
				December 31, 2010				December 31, 2009
				(in thousands)
Derivatives designated as Hedging Instruments under ASC 815
Natural gas		Current derivative asset		$	23,187			$	12,896
Natural gas		Derivative instruments—non-current asset			20,503				19,144
Total derivative asset fair value				$	43,690			$	32,040

 

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		Balance Sheet Location		Liability Fair Value
				December 31, 2010				December 31, 2009
				(in thousands)
Derivatives designated as Hedging Instruments under ASC 815
Natural gas		Current derivative asset		$	2,963			$	—
Natural gas basis		Current derivative asset			566				—
Natural gas		Derivative instruments—non-current asset			2,897				—
Natural gas basis		Derivative instruments—non-current asset			122				549
				$	6,548			$	549
Derivatives not designated as Hedging Instruments under ASC 815
Natural gas		Current derivative asset		$	—			$	374
Natural gas basis		Current derivative asset			—				270
Natural gas		Derivative instruments—non-current asset			—				1,303
Crude oil		Current derivative asset			172				—
					172				1,947
Total derivative liability fair value				$	6,720			$	2,496
Net derivative fair value				$	36,970			$	29,544

Following is a summary of the outstanding volumes and prices on the oil and natural gas swaps and options in place as of December 31, 2010:

 

Effective Date		Maturity Date				Notional Amount Per Month				Remaining Notional Amount as of December 31, 2010				Additional Put Options				Floor				Ceiling				Designation under ASC 815
Natural Gas (MMBtu):
1/1/2011			12/31/2012				155,337				3,728,100			$	—			$	—			$	7.00			Cash flow hedge
1/1/2011			12/31/2011				188,781				2,265,372			$	—			$	—			$	8.00			Cash flow hedge
1/1/2011			3/31/2011				200,000				600,000			$	5.00			$	7.00			$	7.25			Cash flow hedge
1/1/2011			3/31/2011				200,000				600,000			$	—			$	—			$	8.90			Cash flow hedge
4/1/2011			10/31/2011				200,000				1,400,000			$	5.00			$	6.50			$	8.30			Cash flow hedge
11/1/2011			3/31/2012				200,000				1,000,000			$	5.50			$	7.00			$	10.10			Cash flow hedge
1/1/2011			12/31/2012				1,021,666				24,520,000			$	4.00			$	6.00			$	—			Cash flow hedge
1/1/2011			12/31/2012				167,612				4,022,697			$	4.50			$	6.25			$	—			Cash flow hedge
Crude Oil (Bbls):
1/1/2011			12/31/2011				3,042				36,500			$	—			$	—			$	100.00			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.

 

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Effects of derivative instruments on the Consolidated Statement of Operations

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

 

		For the Year Ended December 31, 2010
		Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion)				Location of Gain Reclassified from Accumulated OCI into Income (Effective Portion) and Location of Gain Recognized in  Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)		Amount of Gain Reclassified from Accumulated OCI into  Income (Effective Portion)				Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
		(in thousands)						(in thousands)
Natural gas		$	33,858			Oil and Gas Sales		$	23,585			$	(1,280	)
		For the Year Ended December 31, 2009
		Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion)				Location of Gain Reclassified from Accumulated OCI into Income (Effective Portion) and Location of Gain Recognized in  Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)		Amount of Gain Reclassified from Accumulated OCI into  Income (Effective Portion)				Amount of Gain Recognized in Income  on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
		(in thousands)						(in thousands)
Natural gas		$	20,911			Oil and Gas Sales		$	28,546			$	1,018
Crude oil			(437	)		Oil and Gas Sales			2,305				—
		$	20,474					$	30,851			$	1,018
		For the Year Ended December 31, 2008
		Amount of Gain Recognized in OCI on Derivative (Effective Portion)				Location of Gain Reclassified from Accumulated OCI into Income (Effective Portion) and Location of Gain Recognized in  Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)		Amount of Loss Reclassified from Accumulated OCI into  Income (Effective Portion)				Amount of Gain Recognized in Income  on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
		(in thousands)						(in thousands)
Natural gas		$	14,999			Oil and Gas Sales		$	4,032			$	925
Crude oil			4,115			Oil and Gas Sales			2,027				89
		$	19,114					$	6,059			$	1,014

Assuming that the market prices of oil and gas futures as of December 31, 2010 remain unchanged, the Company would expect to transfer a gain of approximately $9.4 million from accumulated other comprehensive income to earnings during the next 12 months. The actual reclassification into earnings will be based on market prices at the contract settlement date.

 

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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:

 

		Location of Gain (Loss) Recognized in Income on Derivative		Amount of Gain (Loss) Recognized in Income on Derivative
				For the Year Ended
				2010				2009				2008
Realized
Natural gas		Oil and Gas Sales		$	(23	)		$	5,920			$	—
Unrealized
Natural gas		Unrealized losses on derivatives			(221	)			(2,100	)			(354	)
Natural gas basis		Unrealized losses on derivatives			—				(270	)			—
Crude Oil		Unrealized losses on derivatives			99				—				—
				$	(145	)		$	3,550			$	(354	)

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

 

		As of December 31, 2010:												As of December 31, 2009:
		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		$	—			$	37,142			$	—			$	—			$	29,544			$	—
Crude oil derivative instruments		$	—			$	(172	)		$	—			$	—			$	—			$	—

 

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NOTE F—LONG-TERM DEBT

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

 

		December 31,
		2010								2009
		Carrying Amount				Fair Value				Carrying Amount				Fair Value
		(in thousands)
Revolving bank credit facility(1)		$	92,000			$	92,000			$	—			$	—
5.00% Senior Convertible Notes due February 2013			116,365				105,258				115,646				111,406
4.50% Senior Convertible Notes due May 2015			75,238				63,825				73,187				87,652
Joint venture financing(2)			1,366				1,366				1,445				1,445
Total		$	284,969			$	262,449			$	190,278			$	200,503

 

(1)	Maturity date of August 2012 bearing a weighted average interest rate of 4.11% and 3.83% as of December 31, 2010 and 2009, respectively, collateralized by all assets of the Company. See “Note O—Subsequent Events.”

(2)	Non-recourse, no interest rate

Maturities of Long-Term Debt

Maturities of long-term debt as of December 31, 2010 are as follows:

 

Year		Amount
		(in thousands)
2011		$	26
2012			92,019
2013			122,765
2014			11
2015			86,250
Thereafter			1,295
		$	302,366

Revolving Bank Credit Facility

The Company has an executed loan agreement providing for a secured revolving line of credit for up to $250 million in loans as the borrowing base permits, which is based on the Company’s oil and natural gas reserves (the “borrowing base”). The borrowing base at December 31, 2010 was $130 million and may be adjusted from time to time. The loan bears interest at a rate elected by the Company that is based on the prime, LIBO or federal funds rate plus margins ranging from 1% to 4.25% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. Upon delivery by the Company of the monthly EBITDA certificate which sets forth the Total Net Debt to EBITDA ratio as being 4.00 to 1.00 or higher, the applicable LIBO rate margin and the applicable prime rate margin are automatically adjusted, effective on the first day of the month in which the monthly EBITDA certificate is delivered, as set forth in the agreement. The applicable LIBO rate margin will be 6.00% and the applicable prime rate margin will be 3.75%. The increased margins will remain in effect until the Total Net Debt to EBITDA ratio is less than 4.00 to 1.00.

 

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During 2010, the maturity date for amounts borrowed by the Company pursuant to the loan agreement was extended from July 15, 2011, to August 1, 2012, and the Company may automatically extend this new maturity date to July 8, 2013, in certain circumstances. Principal is payable voluntarily by the Company or is required to be paid (i) if the loan amount exceeds the borrowing base; (ii) if the lender elects to require periodic payments as a part of a borrowing base re-determination; and (iii) at the maturity date. The Company is obligated to pay a facility fee equal to 0.5% per year of the unused portion of the borrowing base payable quarterly. The loan is secured by a first mortgage on assets of the Company.

During 2010, the financial covenants of the loan agreement were amended relating to the maximum ratio of total debt to EBITDA (as defined in the Loan Agreement). First, the definition of “total debt” was modified to include only the portions of the Company’s $122.75 million aggregate principal amount of 5.00% senior convertible notes and $86.25 million aggregate principal amount of 4.50% senior convertible notes classified as indebtedness and to exclude the portions of such convertible notes classified as equity under generally accepted accounting principles. Second, the Company is required to maintain, on a monthly basis as of the last day of each month, a ratio (on a rolling twelve month basis) of Total Net Debt to EBITDA during the preceding twelve months not to exceed the following levels:

 

Period		Maximum Ratio
June 1, 2010 through November 30, 2010			4.50 to 1.00
December 1, 2010 through February 28, 2011			4.75 to 1.00
March 1, 2011 through August 31, 2011			4.60 to 1.00
September 1, 2011 through October 31, 2011			4.40 to 1.00
November 1, 2011 through Maturity Date			4.00 to 1.00

Additionally, the Company is required to maintain, on a monthly basis as of the last day of each month, a ratio (on a rolling twelve month basis) of Total Senior Secured Debt to EBITDA (as defined) during the preceding twelve (12) months not to exceed 2.50 to 1.00. “Total Senior Secured Debt” means the Company’s Indebtedness (as defined) plus any other senior secured indebtedness for borrowed money owing by the Company or any subsidiaries which is secured by a lien (whether on any of the Company’s property which is not collateral or on a pari passu basis with the Indebtedness).

The loan agreement contains additional affirmative and restrictive covenants. These covenants, among other things, prohibit additional indebtedness, sales of assets, mergers and consolidations, dividends and distributions, and changes in management and require the maintenance of various financial ratios. The required and actual financials ratios as of December 31, 2010 are shown below:

 

Financial Covenant		Required Ratio		Actual Ratio
Current ratio(1)		Not less than 1 to 1			1.29 to 1
Ratio of Total Net Debt to EBITDA(2)		Not greater than 4.75 to 1			4.62 to 1
Total Senior Secured Debt to EBITDA(2)		Not greater than 2.50 to 1			1.50 to 1
Ratio of EBITDA, as defined in the revolving bank credit facility agreement to cash interest expense(3)		Not less than 3 to 1			3.40 to 1

 

(1)

Current ratio is defined in our revolving bank credit facility as the ratio of current assets plus the unused and available portion of the revolving bank credit facility ($38 million as of December 31, 2010) to current liabilities. The calculation will not include the effects, if any, of derivatives under ASC 815. As of December 31, 2010, current assets included derivatives assets of $19.5 million. In addition, the convertible notes are not considered a current liability unless one or more convertible notes have been surrendered for conversion and then only to the extent of the cash payment due on the conversion of the notes surrendered.

 

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(2)

EBITDA as defined in our revolving bank credit facility as of December 31, 2010 is calculated as follows (amounts in thousands):

 

Net loss		$	(138,292	)
Plus:
Interest expense			18,642
Early extinguishment of debt			(141	)
Impairment of oil and natural gas properties and assets held for sale			143,712
Depreciation, depletion and amortization			38,061
Non-cash compensation and other expenses			4,167
Less:
Income tax benefit			4,239
EBITDA		$	61,910

 

(3)

Cash interest expense is defined in the revolving bank credit facility as all interest, fees, charges, and related expenses payable in cash for the applicable period payable to a lender in connection with borrowed money or the deferred purchase price of assets that is considered interest expense under GAAP, plus the portion of rent paid or payable for that period under capital lease obligations that should be treated as interest. For 2010, cash interest expense included fees paid related to bank financing activities and other loan fees of $1.7 million. As of December 31, 2010, non-cash interest expense of $7.7 million was deducted from interest expense to arrive at the cash interest expense used in the debt covenant calculation. Non-cash interest expense primarily relates to the amortization of debt issuance costs. Capitalized interest of $2.6 million was added to interest expense.

As of December 31, 2010, the Company was in compliance with financial covenants under the revolving bank credit facility. The lenders may accelerate all of the indebtedness under the revolving bank credit facility upon the occurrence of any event of default unless the Company cures any such default within any applicable grace period. For payments of principal and interest under the revolving bank credit facility, the Company generally has a three business day grace period, and a 30-day cure period for most covenant defaults, but not for defaults of certain specific covenants, including the financial covenants and negative covenants.

See “Note O—Subsequent Events.” The loan agreement was amended on February 2, 2011 in connection with the Company’s issuance of senior unsecured notes, sale of common stock and tender offer for at least $50 million of the Company’s convertible senior notes due 2013.

5.00% Convertible Senior Notes

In February 2008, the Company completed a $125 million private placement of 5.00% convertible senior notes due 2013 (“5.00% Convertible Notes”). In connection with such offering, we agreed to loan up to 3,846,150 shares of our common stock to an affiliate of Jefferies & Company, Inc. to facilitate hedging transactions by purchasers of the notes.

On December 21 and December 22, 2010, the Company entered into two separate agreements with a third party to retire $2.25 million of the 5.00% Convertible Notes for a combined total of 380,250 shares of the Company’s common stock and $45,659.72 in cash. The cash consideration satisfies unpaid and accrued interest on the 5.00% Convertible Notes.

As a result of the adoption of the new authoritative accounting guidance under ASC as of January 1, 2009 and its retrospective application, the Company recorded a debt discount of $14.3 million, which represented the fair value of the equity conversion feature, and recorded a corresponding increase in additional paid-in capital (“APIC”), net of deferred taxes. In addition, the transaction costs incurred directly related to the issuance of the 5.00% Convertible Notes were allocated proportionately to the equity conversion feature and recorded as APIC. The equity component is not subsequently re-valued as long as it continues to qualify for equity treatment.

 

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The debt discount is amortized as additional non-cash interest expense over the expected term of the 5.00% Convertible Notes through February 2013. As of December 31, 2010, the net carrying amount was as follows (amounts in the thousands):

 

		2010				2009
Principal amount		$	122,750			$	125,000
Unamortized debt discount			(6,385	)			(9,354	)
Carrying amount		$	116,365			$	115,646

The 5.00% Convertible Notes bear interest at a rate of 5.00% per year, payable semiannually in arrears on February 1 and August 1 of each year, which began 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 amount of the cash interest expense recognized with respect to the 5.00% contractual interest coupon for the years ended December 31, 2010 and 2009 was $6.2 million and $6.3 million, respectively. The amount of non-cash interest expense for the years ended December 31, 2010 and 2009 related to the amortization of the debt discount and amortization of the transaction costs was $3.7 million and $3.5 million, respectively. As of December 31, 2010, the unamortized discount is expected to be amortized into earnings over 2.1 years. The carrying value of the equity component of the 5.00% Convertible Notes was $9.2 million as of December 31, 2010.

Holders may convert their 5.00% Convertible Notes at their option prior to the close of business on the business day immediately preceding November 1, 2012 only under the following circumstances:

 

•

during any fiscal quarter commencing after March 31, 2008 if the last reported sale price of the common stock for at least 20 trading days during a period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter is greater than or equal to 130% of the applicable conversion price on each such trading day;

 

•

during the five business-day period after any five consecutive trading-day period in which the trading price for each day of that measurement period was less than 98% of the last reported sale price of our common stock and the applicable conversion rate on each such day; or

 

•

the occurrence of certain sales of assets, distributions or changes to distribution rights to common stockholders, mergers and consolidations, changes in management, or our common stock ceases to be listed on a United States national or regional securities exchange, among other things.

On and after November 1, 2012 until the close of business on the business day immediately preceding the maturity date, holders may convert their 5.00% Convertible Notes at any time, regardless of the foregoing circumstances.

Upon conversion, the Company will satisfy its conversion obligation by paying and delivering cash for the lesser of the principal amount or the conversion value, and, if the conversion value is in excess of the principal amount, by paying or delivering, at its option, cash and/or shares of its common stock for such excess. The conversion value is a daily value calculated on a proportionate basis for each day of a 60 trading-day observation period. The conversion rate is initially 30.7692 shares of the Company’s common stock per $1,000 principal amount of notes (equivalent to a conversion price of approximately $32.50 per share of common stock). The conversion rate is subject to adjustment in some events but will not be adjusted for accrued interest. In addition, following any fundamental change that occurs prior to the maturity date, we will increase the conversion rate for a holder who elects to convert its 5.00% Convertible Notes in connection with such a fundamental change in certain circumstances. The increase in the conversion rate is determined based on a formula that takes into consideration our stock price at the time of the fundamental change (ranging from $25.00 to $150.00 per share) and the remaining time to maturity of the notes. The increase in the conversion rate ranges from 0% to 30% increasing as the stock price at the time of the fundamental change increases from $25.00 and declines as the remaining time to maturity of the notes decreases.

 

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We may not redeem the 5.00% Convertible Notes prior to maturity. However, if we undergo a fundamental change, holders may require us to repurchase the 5.00% Convertible Notes in whole or in part for cash at a price equal to 100% of the principal amount of the 5.00% Convertible Notes to be repurchased plus any accrued and unpaid interest (including additional interest, if any) to, but excluding, the fundamental change repurchase date.

The 5.00% Convertible Notes are senior unsecured obligations of the Company and rank equally in right of payment to all of the Company’s other existing and future senior indebtedness. The 5.00% Convertible Notes are effectively subordinated to revolving bank credit facility, to the extent of the value of our assets pledged as collateral for such indebtedness. The 5.00% Convertible Notes are also effectively subordinated to all liabilities of our subsidiaries, including liabilities under any guarantees they have issued.

See “Note O—Subsequent Events.” On January 28, 2011, the Company offered to tender for up to $50 million aggregate principal at its 5.00% Convertible Senior Notes due 2013 in connection with the sale of common stock and the issuance of $200 million of senior notes due 2019.

4.50% Convertible Senior Notes

In October 2009, the Company completed a $86.3 million private placement of 4.50% convertible senior notes due 2015 (“4.50% Convertible Notes”). The proceeds of the offering were used to repay the Senior Subordinated Secured Notes due 2012 and a portion of the outstanding indebtedness under the revolving bank credit facility. The Company recorded a debt discount of $13.4 million, which represented the fair value of the equity conversion feature, and recorded a corresponding increase in APIC, net of deferred taxes. In addition, the transaction costs incurred directly related to the issuance of the 4.50% Convertible Notes were allocated proportionately to the equity conversion feature and recorded as APIC. The equity component is not subsequently re-valued as long as it continues to qualify for equity treatment. As of December 31, 2010, the net carrying amount was as follows (amounts in thousands):

 

		2010				2009
Principal amount		$	86,250			$	86,250
Unamortized debt discount			(11,012	)			(13,063	)
Carrying amount		$	75,238			$	73,187

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 year ended December 31, 2010 was $3.9 million. The amount of non-cash interest expense for the year ended December 31, 2010 related to the amortization of the debt discount and amortization of the transaction costs was $2.5 million. As of December 31, 2010, the unamortized discount is expected to be amortized into earnings over 4.3 years. The carrying value of the equity component of the 4.50% Convertible Notes was $8.4 million as of December 31, 2010.

The 4.50% Convertible Notes mature on May 1, 2015, unless earlier converted or repurchased by us. Holders may convert their notes prior to the close of business on the business day immediately preceding February 1, 2015, only under the following circumstances:

 

•

during any fiscal quarter commencing after January 1, 2010, if the last reported sale price of our common stock for at least 20 trading days during a period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter is greater than or equal to 130% of the applicable conversion price on each such trading day;

 

F-29

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•

during the five business-day period after any five consecutive trading-day period in which the trading price per $1,000 principal amount of 4.50% Convertible Notes for each day of such five consecutive trading-day period was less than 98% of the product of the last reported sale price of our common stock and the applicable conversion rate on each such day;

 

•

upon the occurrence of a corporate event pursuant to which: (1) we issue rights to all or substantially all of the holders of our common stock entitling them to purchase, for a period of not more than 60 calendar days after the announcement date of such issuance to subscribe for or purchase, shares of our common stock at a price per share less than the average of the last reported sale prices of our common stock for the 10 consecutive trading day period ending on the trading day immediately preceding the date of announcement of such issuance; (2) we distribute to all or substantially all of the holders of our common stock our assets, debt securities or rights to purchase our securities, if the distribution has a per share value in excess of 10% of the last reported sale price for our common stock on the trading day immediately preceding the date of announcement of such distribution; or (3) we are a party to a consolidation, merger, binding share exchange, or transfer or lease of all or substantially all of our assets, pursuant to which our common stock would be converted into cash, securities or other assets;

 

•

if: (1) a “person” or “group” within the meaning of Section 13(d) of the Exchange Act acquires more than 50% of our outstanding voting stock, (2) we consummate a recapitalization, reclassification or change of our common stock as a result of which our common stock would be converted into or exchanged for stock, other securities, other property or assets, less than 90% of which received by our common shareholders consists of publicly traded securities, (3) we consummate a share exchange, consolidation or merger pursuant to which our common stock will be converted into cash, securities or other property, (4) we consummate any sale, lease or other transfer in one transaction or a series of transactions of all or substantially all of our and our subsidiaries’ consolidated assets to any person other than one of our subsidiaries, (5) continuing directors cease to constitute at least a majority of our board of directors, (6) our shareholders approve any plan or proposal for our liquidation or dissolution, or (7) our common stock ceases to be listed on any of The New York Stock Exchange, The NASDAQ Global Select Market or The NASDAQ Global Market; or

 

•

if we call the 4.50% Convertible Notes for redemption, at any time prior to the close of business on the business day prior to the redemption date (any of the events described in the fourth and fifth bullets above, a “make-whole fundamental change”).

On and after February 1, 2015 until the close of business on the business day immediately preceding the maturity date, holders may convert their 4.50% Convertible Notes, in multiples of $1,000 principal amount, at the option of the holder regardless of the foregoing circumstances.

Upon conversion, we will satisfy our conversion obligation by paying or delivering cash, shares of our common stock or a combination of cash and shares of our common stock, at our election. The conversion rate is initially 53.3333 shares of our common stock per $1,000 principal amount of 4.50% Convertible Notes (equivalent to a conversion price of approximately $18.75 per share of our common stock). The conversion rate is subject to adjustment in some events but will not be adjusted for accrued and unpaid interest. In addition, following any make-whole fundamental change that occurs prior to the maturity date, we will increase the conversion rate for a holder who elects to convert its 4.50% Convertible Notes in connection with such a make-whole fundamental change in certain circumstances. The increase in the conversion rate is determined based on a formula that takes into consideration our stock price at the time of the make-whole fundamental change (ranging from $15.00 to $100.00 per share) and the remaining time to maturity of the 4.50% Convertible Notes. The increase in the conversion rate declines from a high of 25.0% to 0.0% as the stock price at the time of the make-whole fundamental change increases from $15.00 and the remaining time to maturity of the 4.50% Convertible Notes decreases.

On or after November 1, 2012, and prior to the maturity date, we may redeem for cash all, but not less than all, of the 4.50% Convertible Notes if the last reported sales price of our common stock equals or exceeds 130%

 

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of the conversion price then in effect for 20 or more trading days in a period of 30 consecutive trading days ending on the trading day immediately prior to the date of the redemption notice. The redemption price will equal 100% of the principal amount of the 4.50% Convertible Notes to be redeemed, plus any accrued and unpaid interest, including any additional interest, to, but excluding, the redemption date. To the extent a holder converts its 4.50% Convertible Notes in connection with our redemption notice, we will increase the conversion rate as described in the preceding paragraph.

The 4.50% Convertible Notes are senior, unsecured obligations of the Company and rank equally in right of payment with our senior unsecured debt and our existing 5.00% Convertible Notes, and are senior in right of payment to our debt that is expressly subordinated to the 4.50% Convertible Notes, if any. The 4.50% Convertible Notes are structurally subordinated to all debt and other liabilities and commitments of our subsidiaries, including our subsidiaries’ guarantees of our indebtedness under our revolving bank credit facility, and are effectively junior to our secured debt to the extent of the assets securing such debt.

Senior Subordinated Secured Notes

In July 2007, we entered into a Note Purchase Agreement (“Note Agreement”) with The Prudential Insurance Company of America (“Prudential”) providing for the issuance and sale from time to time of up to $100 million in senior subordinated secured notes (the “Secured Notes”) and sold to Prudential an initial tranche of $30 million of 7.58% Series A fixed rate notes due July 31, 2012 with interest payable quarterly. Proceeds from the sale of the Secured Notes were used for general corporate purposes including additional funding of drilling and development costs in the Cotton Valley Sands in East Texas. On October 18, 2009, the Company entered into an amendment with Prudential to provide for the repayment of the outstanding indebtedness of the Secured Notes. The Company repaid all of the outstanding indebtedness under the Secured Notes with a portion of the proceeds from the 4.50% Convertible Senior Notes issued in October 2009. The terms of the repayment included a prepayment penalty of $4.6 million. Additionally, we expensed approximately $0.3 million in deferred debt issue costs for the year ended December 31, 2009.

Joint Venture Financing

In 2004, we entered into an arrangement with PVOG to purchase dollar denominated production payments from the Company on certain wells drilled during a portion of 2004. Under this agreement, PVOG provided $2.8 million in funding for our share of costs of four wells drilled which is repayable solely from 75% of GMX’s share of production revenues from these wells without interest.

NOTE G—ASSET RETIREMENT OBLIGATIONS

The activity incurred in the asset retirement obligation is as follows:

 

		2010				2009
		(in thousands)
Beginning balance		$	6,789			$	6,049
Liabilities incurred			269				324
Liabilities settled			(467	)			(204	)
Accretion			412				378
Revisions			275				242
Ending balance(1)			7,278				6,789
Less current portion(1)			406				259
		$	6,861			$	6,530

 

(1)

The Company’s liability for asset retirement obligations is included in other liabilities in the consolidated balance sheets, net of the current obligations. The current portion is included in accrued expenses in the consolidated balance sheets.

 

F-31

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NOTE H—INCOME TAXES

Income tax expense (benefit) consists of the following for the years ended December 31:

 

		2010				2009				2008
		(in thousands)
Current tax expense (benefit)		$	(30	)		$	(33	)		$	26
Deferred tax expense (benefit)			(4,209	)			—				(26,243	)
		$	(4,239	)		$	(33	)		$	(26,217	)

Total income tax expense (benefit) differed from the amounts computed by applying the U.S. federal tax rate to earnings before income taxes as a result of the following for the years ended December 31:

 

		2010				2009				2008
U.S. statutory tax rate			34	%			34	%			34	%
Statutory depletion			3				—				(4	)
Change in valuation allowance			(37	)			(33	)			(17	)
Other			3				(1	)			4
Effective income tax rate			3	%			—	%			17	%

Intangible development costs may be capitalized or expensed for income tax reporting purposes, whereas they are capitalized and amortized for financial statement purposes. Lease and well equipment and other property and equipment may be depreciated for income tax reporting purposes using accelerated methods and different lives. Other temporary differences include the effect of hedging transactions and stock based compensation awards. Deferred income taxes are provided on these temporary differences to the extent that income taxes which otherwise would have been payable are reduced. Deferred income tax assets are also available to offset future income taxes.

The following table sets forth the Company’s deferred tax assets and liabilities at December 31:

 

		2010				2009 (as adjusted)				2008 (as adjusted)
		(in thousands)
Deferred tax assets:
Federal net operating loss carryforwards		$	71,911			$	26,500			$	13,132
Property and equipment			10,644				548				—
Statutory depletion carryforwards			5,723				2,245				3,588
Stock compensation expense			1,416				1,030				641
Derivative instruments			704				662				734
Oil and natural gas properties			56,992				60,089				23,059
Other			480				431				34
Valuation allowance on deferred tax assets not expected to be realized			(133,451	)			(79,182	)			(25,037	)
Total			14,419				12,323				16,151
Deferred tax liabilities:
Property and equipment			—				—				(1,983	)
Derivative instruments			(8,066	)			(4,237	)			(9,260	)
Convertible debt and share lending agreement			(6,353	)			(8,086	)			(4,908	)
Total			(14,419	)			(12,323	)			(16,151	)
Net deferred tax asset (liability)		$	—			$	—			$	—

 

F-32

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The valuation allowance for deferred tax assets increased by $54.2 million in 2010. In determining the carrying value of a deferred tax asset, accounting standards provides for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. As we have incurred net operating losses in 2010 and prior years, relevant accounting guidance suggest 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. Therefore, with the before mentioned adjustment of $54.2 million, we continue to reduce the carrying value of our net deferred tax asset to zero for 2010, which has been the case in prior years. The valuation allowance has no impact on our net operating loss (“NOL”) position for tax purposes, and if we generate taxable income in future periods, we will be able to use our 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.

At December 31, 2010, the Company had federal net operating loss carryforwards of $211.5 million which will begin to expire in 2018 if unused. The Company’s federal net operating loss carryforward has an annual limitation under Internal Revenue Code Section 382. In addition, at December 31, 2010, the Company had tax percentage depletion carryforwards of approximately $16.8 million which are not subject to expiration.

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and in various states. With few exceptions, the Company is no longer subject to U.S. federal or state income tax examinations by these tax authorities for years before and including 2006. We have not paid any significant interest or penalties associated with our income taxes, but classify both interest expense and penalties as part of our income tax expense.

NOTE I—COMMITMENTS AND CONTINGENCIES

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.

The Company leases offices and certain equipment under operating leases and has contracts with a drilling contractor for the use of four rigs with 3 year terms. Additionally, in 2010, the Company entered into a firm transportation and a firm sales contract for various terms through 2020. Under these contracts, the Company is obligated to transport or sell minimum daily gas volumes, as calculated on a monthly basis, or pay for any deficiencies, at a set rate. The firm transportation contract for 50 Mmbtu per day commences with the completion of a pipeline which occurred in the first quarter of 2010. An additional sales contract was effective in September 2009 for 15 Mmbtu per day and increases through 2014 up to 100 Mmbtu per day. These commitments are not recorded in the accompanying consolidated balance sheets.

The following is schedule by year of these obligations and minimum lease payments at December 31, 2010:

 

Year		Operating Leases				Transportation				Drilling Contracts				Total
		(in thousands)
2011		$	1,129			$	6,043			$	22,948			$	30,120
2012			1,118				6,190				22,463				29,771
2013			802				6,349				1,153				8,304
2014			491				5,970				—				6,461
2015			555				5,668				—				6,223
Thereafter			662				22,672				—				23,334
Total		$	4,757			$	52,892			$	46,564			$	104,213

 

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Rent expense on operating leases for the years ended December 31, 2010, 2009 and 2008 was $2.8 million, $1.4 million and $693,000, respectively.

NOTE J—STOCK COMPENSATION PLANS

We recognized $6.6 million, $4.6 million and $3.1 million of stock compensation expense for the years ending December 31, 2010, 2009 and 2008, respectively. These non-cash expenses are reflected as a component of the Company’s general and administrative expense. To the extent amortization of compensation costs relates to employees directly involved in exploration and development activities, such amounts are capitalized to oil and natural gas properties. Stock based compensation capitalized as part of oil & natural gas properties was $1.0 million and $1.2 million for the years ended December 31, 2010 and 2009.

2008 Long-Term Incentive Plan

In May 2008, the Board of Directors and shareholders adopted the 2008 Long-Term Incentive Plan (or “LTI Plan”) to retain and attract employees, consultants and directors, and to stimulate the active interest in the development and financial success of the Company. The LTI Plan provides for the grant of stock options, restricted stock awards, bonus stock awards, stock appreciation rights, performance units and performance bonuses, subject to certain conditions.

On June 17, 2010, the LTI Plan was amended. Under the terms of the amended LTI Plan, the aggregate number of shares of common stock available for awards may not exceed 1,750,000 shares. Of the shares available for issuance under the LTI Plan as of the amendment date of the LTI Plan, 750,000 could be granted as “incentive stock options” as defined in Section 422 of the Internal Revenue Code of 1986, as amended (the “Code”).

2000 Stock Option Plan

In October 2000, the Board of Directors and shareholders adopted the GMX Resources Inc. Stock Option Plan (the “2000 Option Plan”). Under the 2000 Option Plan, the Company may grant both stock options intended to qualify as incentive stock options under Section 422 of the Internal Revenue Code and options which are not qualified as incentive stock options.

The maximum number of shares of common stock issuable under the 2000 Option Plan, as amended in May 2007, is 850,000, subject to appropriate adjustment in the event of reorganization, stock split, stock dividend, reclassification or other change affecting the Company’s common stock. All officers, employees and directors are eligible to receive awards under the 2000 Option Plan. The exercise price of options granted is not less than 100% of the fair market value of the shares on the date of grant. Options granted become exercisable as the Board of Directors may determine in connection with the grant of each option. In addition, the Board of Directors may at any time accelerate the date that any option granted becomes exercisable. Stock options generally vest over four years and have a 10-year contractual term. 25,698 options were accelerated in vesting during 2010 as a result of agreements with terminated employees. There have been no options for which vesting was accelerated in 2009 and 2008.

The 2000 Option Plan terminated on October 30, 2010, and no options will be granted pursuant to this plan except with respect to awards then outstanding.

 

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Stock Options

The following table provides information related to stock option activity under the 2000 Option Plan for the years ended December 31, 2008, 2009 and 2010:

 

		Number of shares underlying options				Weighted average exercise price per share				Aggregate intrinsic value(1) (in thousands)				Weighted average grant date fair value per share
Outstanding as of December 31, 2007			574,500			$	28.86
Granted			100,000				25.84							$	25.84
Exercised			(73,450	)			13.34			$	2,396
Forfeited			(18,000	)			33.41
Outstanding as of December 31, 2008			583,050				30.16
Exercised			(750	)			6.10			$	3
Forfeited			(5,500	)			33.95
Outstanding as of December 31, 2009			576,800				30.16
Granted			48,001				6.34							$	4.36
Forfeited			(48,750	)			32.84
Outstanding as of December 31, 2010			576,051			$	27.93			$	—
Exercisable as of December 31, 2010			446,050			$	29.11			$	—

 

(1)	The intrinsic value is the amount by which the market value of the underlying stock exceeds the exercise price.

The weighted-average remaining contractual life of outstanding and exercisable options at December 31, 2010 was 5.18 and 4.10 years, respectively. As of December 31, 2010 there was $649,186 of total unrecognized compensation costs related to non-vested stock options granted under the Company’s stock option plan. That cost is expected to be recognized over a weighted average period of 1.2 years.

The fair value of each stock award is estimated on the date of grant using the Black-Scholes option pricing model. Assumptions used in the valuation are disclosed in the following table:

 

		2010				2009				2008
Expected volatility			77.2	%			—				41.3	%
Expected dividend yields			0	%			—				0	%
Expected term (in years)			6.25				—				4
Risk free rate			2.2	%			—				2.7	%

The Company estimated volatility is based on the historical volatility of the Company’s common stock. The risk free interest rate is based on the U. S. Treasury yield curve in effect at the time of grant for the expected term of the option. The expected dividend yield is based on the Company’s current dividend yield and the best estimate of projected dividend yield for future periods within the expected life of the option.

Restricted Stock

In July 2008, the Company began issuing restricted stock awards to its officers, independent directors, consultants and certain employees under the LTI Plan. The holders of these shares have all the rights and privileges of owning the shares (including voting rights) except that the holders are not entitled to delivery of a portion thereof until certain passage of time requirements are met. With respect to the restricted stock granted to officers, consultants, and employees of the Company, the shares generally vest over a 3 or 4 year period. With

 

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respect to restricted shares issued to the Company’s independent board members, the shares vest over a two year period. The fair value of the awards issued is determined based on the fair market value of the shares on the date of grant. The value is amortized over the vesting period. In 2010, 74,799 restricted shares accelerated vesting as a result of termination agreements with employees.

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

 

		Number of unvested restricted shares				Weighted average grant- date fair value per share
Unvested shares as of January 1, 2008			—			$	—
Granted			79,347			$	74.11
Vested			(16,521	)		$	76.65
Forfeited			(98	)		$	76.73
Unvested shares as of December 31, 2008			62,728			$	73.44
Granted			542,847			$	18.55
Vested			(23,574	)		$	70.38
Forfeited			(1,471	)		$	29.00
Unvested shares as of December 31, 2009			580,530			$	22.35
Granted			359,385			$	6.34
Vested			(220,016	)		$	24.21
Forfeited			(27,903	)		$	23.11
Unvested shares as of December 31, 2010			691,996			$	13.47

As of December 31, 2010, there was $9.3 million of unrecognized compensation expense related to non-vested restricted stock grants. This unrecognized compensation cost is expected to be recognized over a weighted-average period of 2.3 years.

The vesting of certain restricted stock grants results in state and federal income tax benefits related to the difference between the market price of the common stock at the date of vesting and the date of grant. During the years ended December 31, 2010 and 2009, we did not recognize excess tax benefits related to the vesting of restricted stock due to the market price of the common stock at the date of grant exceeding the market price at the vesting date.

401(k) Plan

The GMX Resources Inc. 401(k) Plan was adopted April 15, 2001. The plan is a qualified retirement plan under the Internal Revenue Code. All employees are eligible who have attained age 21. GMX matches the employee contributions up to 5% of the employee’s gross wages. The Company contributed $449,000, $281,000 and $448,000 in 2010, 2009 and 2008, respectively.

NOTE K—CAPITAL STOCK

In July 2008, GMX completed an offering of 2,000,000 shares of its common stock for $70.50 per share. Net proceeds to the Company were approximately $134.0 million. The Company repaid outstanding indebtedness under its revolving bank credit facility. The balance of the net proceeds were used to fund the development of oil and natural gas properties, acquisitions of additional oil and natural gas properties and for general corporate purposes.

 

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In May 2009, GMX completed an offering of 5,750,000 shares of its common stock for $12.00 per share. Net proceeds to the Company were $65.3 million. The Company used the net proceeds from this offering to repay outstanding indebtedness under its revolving bank credit facility.

In October 2009, GMX completed an offering of 6,950,000 shares of its common stock at $15.00 per share. Net proceeds to the Company were approximately $98.8 million. The Company used the net proceeds from this offering, along with the proceeds from the concurrent issuance of the 4.50% Convertible Notes, to repay the outstanding indebtedness under its revolving bank credit facility and to repay all of its outstanding senior subordinated secured notes, and for general corporate purposes.

As mentioned in “Note F—Long-Term Debt,” in December, 2010, the Company converted $2.25 million of the 5.00% Convertible Notes for a combined total of 380,250 shares of the Company’s common stock.

In August 2006, GMX sold 2,000,000 shares of 9.25% Series B Cumulative Preferred Stock at $25.00 per share in a public offering, resulting in a total offering of $50 million. The net proceeds of $47.1 million from the sale of preferred stock were used to fund the drilling and development of the Company’s East Texas properties and for other general corporate purposes.

In December 2010, GMX sold 41,169 shares of the Series B Cumulative Preferred stock in connection with a continuing “at-the-market” offering.

The annual dividends on each share of Series B Cumulative Preferred Stock are $2.3125 and is payable quarterly when, as and if declared by GMX, in cash (subject to specified exceptions), in arrears to holders of record as of the dividend payment record date, on or about the last calendar day of each March, June, September and December.

The Series B Cumulative Preferred Stock is not convertible into the GMX’s common stock and can be redeemed at the Company’s option after September 30, 2011 at $25.00 per share. The Series B Cumulative Preferred Stock will be required to be redeemed prior to September 30, 2011 at specified redemption prices and thereafter at $25.00 per share in the event of a change of ownership or control of GMX if the acquirer is not a public company meeting certain financial criteria.

 

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NOTE L—OIL AND NATURAL GAS OPERATIONS

Costs incurred in oil and natural gas property acquisitions, exploration, and development activities are as follows for the years ended December 31:

 

		2010				2009				2008
		(in thousands)
Development and exploration costs:
Development drilling		$	7,788			$	14,202			$	183,081
Exploratory drilling			164,355				116,250				15,943
Tubular and other drilling inventories			3,167				1,697				39,773
Asset retirement obligation			706				565				2,407
			176,016				132,714				241,204
Acquisition:
Proved			3,884				6,881				23,246
Unproved(1)			8,149				11,450				26,236
			12,033				18,331				49,482
Total		$	188,049			$	151,045			$	290,686

 

(1)	Includes $2.6 million, $1.8 million and $361,000 of capitalized interest for the years ended December 31, 2010, 2009 and 2008, respectively.

Costs excluded from amortization are as follows at December 31:

 

		2010				2009
		(in thousands)
Unproved property acquisition		$	37,006			$	33,122
Exploratory drilling			2,688				6,667
		$	39,694			$	39,789

Unproved property acquisition costs include costs to acquire new leasehold, unevaluated leaseholds, and capitalized interest. Of the $37.0 million of unproved property costs at December 31, 2010 being excluded from the amortization base, $8.1 million, $11.5 million and $21.0 million were incurred in 2010, 2009, and 2008, respectively. Subject to industry conditions, evaluation of most of these properties and the inclusion of their costs in the amortized capital costs is expected to be completed within three years.

The average DD&A rate per equivalent unit of production was $1.88, $1.76 and 2.08 for the years ended December 31, 2010, 2009 and 2008, respectively.

NOTE M—SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (UNAUDITED)

In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 and 2010 reserve information. In January 2010, the FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. We adopted the guidance as of December 31, 2009 in conjunction with our year-end reserve report as a change in accounting principle that is inseparable from a change in accounting estimate. Under the SEC’s final rule, reserves recorded for the year ended December 31, 2008 were not restated. The primary impacts in 2009 of the SEC’s final rule included:

 

•

the use of the 2009 twelve-month average of the first-day-of-the-month reference prices (prior to adjustment for location and quality differentials) of $61.18 per Bbl for oil and $3.87 per MMBtu for

 

F-38

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natural gas compared to the year-end 2009 reference prices (prior to adjustment for location and quality differentials) of $79.36 per Bbl for oil and $5.79 per MMBtu for natural gas resulted in negative revisions of 16 Bcfe;

 

•

certain of our undeveloped locations are not scheduled to be developed within five years of December 31, 2009, had the impact of reducing our proved undeveloped reserves by 25 Bcfe; and

 

•

applying the same pricing methodology that was in effect for 2008 in 2009 would have resulted in the recognition of an additional 99 Bcfe in reserves at December 31, 2009.

In addition to the 2009 pricing discussed above, the twelve month average of the first-day-of-the-month reference prices (prior to adjustment for location and quality differentials) for 2010 were $79.43 per Bbl for oil and $4.38 per MMBtu for natural gas. For 2008, prior to the SEC issuing its final rule, the reference price was $44.60 per Bbl for oil and $5.71 per MMBtu for natural gas.

All of our reserves were located in the United States. Our reserves were based upon reserve reports prepared by the independent petroleum engineers of MHA Petroleum Consultants, Inc. (“MHA”) and DeGolyer and MacNaughton (“D&M”). Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data.

Therefore, the Standardized Measure shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Decreases in the prices of oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves, reserve volumes and our revenues, profitability and cash flow.

As of December 31, 2010, our reserves shown are net wellhead volumes that have been reduced for lease use volumes (volumes that are consumed or lost between the wellhead and the point of custody transfer). Prior to December 31, 2010, wellhead volumes had not been reduced for lease use volumes which were estimated to be 11% and 10% of ending proved reserves as of December 31, 2009 and 2008, respectively. Historically, the Company had reduced the natural gas price used in determining future cash inflows to compensate for lease use volumes and in determining net realized price.

 

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Estimated Quantities of Oil and Natural Gas

The following table sets forth certain data pertaining to our proved, proved developed and proved undeveloped reserves for the three years ended December 31, 2010.

 

		OIL (MBBLS)				GAS (MMCF)
December 31, 2008
Proved reserves, beginning of period			4,693				406,342
Extensions, discoveries, and other additions			1,613				132,434
Production			(190	)			(11,777	)
Revisions of previous estimates			(1,112	)			(91,678	)
Proved reserves, end of period			5,004				435,321
December 31, 2009
Proved reserves, beginning of period			5,004				435,321
Extensions, discoveries, and other additions			38				25,672
Production			(119	)			(12,908	)
Revisions of previous estimates			(1,244	)			(114,873	)
Proved reserves, end of period			3,679				333,212
December 31, 2010
Proved reserves, beginning of period			3,679				333,212
Extensions, discoveries, and other additions			—				232,629
Production			(95	)			(16,901	)
Revisions of previous estimates			(2,363	)			(236,991	)
Proved reserves, end of period			1,221				311,949
Proved Developed Reserves
December 31, 2007			1,776				144,164
December 31, 2008			1,920				150,585
December 31, 2009			1,439				124,611
December 31, 2010			1,221				157,027
Proved Undeveloped Reserves
December 31, 2007			2,917				262,178
December 31, 2008			3,084				284,736
December 31, 2009			2,240				208,601
December 31, 2010			—				154,922

Revisions of Previous Estimates

In 2010, we had negative revisions of 251 Bcfe, which was primarily the result of all of our Cotton Valley Sands undeveloped locations being removed for adherence with the SEC 5-year guideline for booking our proved reserves, resulting in a negative revision of 219.6 Bcfe. In addition to the Cotton Valley Sands undeveloped locations, the Company also had negative revisions of 10.2 Bcfe related to individual well production history and 16.2 Bcfe related to reporting reserves at net well head volumes.

In 2009, we had negative revisions of 122 Bcfe. Certain of our Cotton Valley Sands undeveloped locations are scheduled for development beyond five years and were excluded from our proved reserves, resulting in a negative revision of 53 Bcfe. The proved reserves for Cotton Valley Sands producers were reduced by 53 Bcfe based on individual well production history. Negative revisions of 16 Bcfe were related to lower natural gas prices as declines in prices result in certain reserves becoming uneconomic at earlier periods.

 

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In 2008, we had a total of 98 Bcfe of negative revisions primarily related to the significant decline in oil and natural gas prices at December 31, 2008 as declines in prices result in certain reserves becoming uneconomic at earlier periods.

Extensions, Discoveries and Other Additions

In 2010, we had a total of 233 Bcfe of extensions and discoveries in the Haynesville Shale resulting from successful drilling during 2010 that extended and developed the proved acreage.

In 2009, we had a total of 25 Bcfe of extensions and discoveries, including 22 Bcfe in the Haynesville Shale resulting from successful drilling during 2009 that extended and developed the proved acreage.

In 2008, the increases in proved reserves from extensions and discoveries is the direct result of additional drilling on our acreage in the Cotton Valley Sands formation.

Standardized measure of discounted future net cash flows

The Standardized Measure of discounted future net cash flows (discounted at 10%) from production of proved reserves was developed as follows:

 

•

An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.

 

•

In accordance with SEC guidelines, the engineers’ estimates of future net revenues from our proved properties and the present value thereof for 2009 and 2010 are made using the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. 2008 estimates were not required to be restated and reflect previously disclosed estimates using year-end prices. These prices are held constant throughout the life of the properties. Oil and natural gas prices are adjusted for each lease for quality, contractual agreements, and regional price variations.

 

•

The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs in effect at December 31 of the year presented and held constant throughout the life of the properties.

 

•

Future income taxes were calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations.

The following summary sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure as of December 31:

 

		2010				2009				2008
		(in thousands)
Future cash inflows		$	1,381,031			$	1,540,047			$	2,586,574
Future production costs			(401,387	)			(591,102	)			(1,014,500	)
Future development costs			(286,897	)			(323,246	)			(559,777	)
Future income tax provisions			—				—				(187,084	)
Net future cash inflows			692,747				625,699				825,213
Less effect of a 10% discount factor			(442,857	)			(437,121	)			(596,420	)
Standardized measure of discounted future net cash flows		$	249,890			$	188,578			$	228,793

 

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Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows at December 31:

 

		2010				2009				2008
		(in thousands)
Standardized measure, beginning of year		$	188,578			$	228,793			$	427,730
Sales of oil and natural gas, net of production costs			(62,847	)			(45,233	)			(110,375	)
Net changes in prices and production costs			164,062				(135,218	)			(255,999	)
Change in estimated future development costs			300,915				76,929				96,063
Extensions and discoveries, net of future development costs			113,367				60,206				49,551
Previously estimated development cost incurred			5,761				143,316				120,028
Revisions of quantity estimates			(260,272	)			(82,836	)			(106,288	)
Accretion of discount			68,045				83,475				164,367
Changes in timing of production and other			(267,719	)			(192,723	)			(269,525	)
Net changes in income taxes			—				51,869				113,241
Standardized measure, end of year		$	249,890			$	188,578			$	228,793

NOTE N—QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized unaudited quarterly financial data for 2010 and 2009 are as follows:

 

		First Quarter				Second Quarter				Third Quarter				Fourth Quarter
		(in thousands, except per share data)
2010
Oil and gas sales		$	21,300			$	23,213			$	24,833			$	27,177
Income (loss) before income taxes(1)			(504	)			1,167				1,570				(144,763	)
Net income (loss)(1)			5,284				(1,202	)			4,504				(146,878	)
Net income applicable (loss) to GMX Common Shareholders(1)			3,815				(2,977	)			2,168				(149,045	)
Basic earnings (loss) per share(2)			0.14				(0.11	)			0.08				(5.27	)
Diluted earnings (loss) per share(2)			0.14				(0.11	)			0.08				(5.27	)
		First Quarter  (as adjusted)(3)				Second Quarter  (as adjusted)(3)				Third Quarter  (as adjusted)(3)				Fourth Quarter  (as adjusted)(3)
		(in thousands, except per share data)
2009
Oil and gas sales		$	22,826			$	22,837			$	23,075			$	25,556
Income (loss) before income taxes(1)			(134,430	)			2,737				1,687				(51,114	)
Net income (loss)(1)			(132,002	)			(216	)			(1,381	)			(47,487	)
Net income (loss) applicable to GMX Common Shareholders(1)			(133,158	)			(1,373	)			(2,537	)			(48,816	)
Basic earnings (loss) per share(2)			(8.67	)			(0.08	)			(0.12	)			(1.88	)
Diluted earnings (loss) per share(2)			(8.67	)			(0.08	)			(0.12	)			(1.88	)

 

(1)

Includes impairment charges on our oil and natural gas properties due to a ceiling test write-down of $138.1 million, $50.1 million and $132.8 million for the first quarter 2009 fourth quarter 2009 and fourth quarter 2010, respectively. In addition, the fourth quarter 2010 loss includes $10.9 million in impairment related to assets classified as held for sale (see Note D).

(2)	The sum of the per share amounts per quarter does not equal the per share amount for the year due to the changes in the average number of common shares outstanding.

(3)	Amounts adjusted for adoption of new issued accounting standards related to the adoption of ASU 2009-15. See “Note B—share Lending Agreement and Adoption of ASU 2009-15.”

 

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NOTE O—SUBSEQUENT EVENTS

Undeveloped Leasehold Acquisitions:

In January 2011, the Company entered into five transactions to purchase undeveloped leasehold located in the Williston Basin in North Dakota/Montana, targeting the Bakken/Sanish-Three Forks Formation, as well as in the oil window of the DJ Basin in Wyoming, targeting the emerging Niobrara Formation. A summary of the transactions are as follows:

 

•

Niobrara acquisition—an agreement to purchase all of the working interest and an 80% net revenue interest in approximately 30,834 undeveloped acres of oil and gas leases located in the Niobrara basin in Wyoming for approximately $27.8 million, including commissions. The Company closed the transaction relating to these properties on February 14, 2011. Pursuant to our agreements with the seller, the seller has the option to reacquire 50% of the working interest acquired by us in these properties at the same purchase price paid by us within three months following the closing of this transaction.

 

•

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

 

•

Niobrara acquisition-Retamco—a separate purchase and sale agreement with Retamco Operating, Inc. relating to the acquisition by the Company of all of the working interest and an 80% net revenue interest in approximately 9,809 undeveloped net acres of oil and gas leases located in the Niobrara basin in Wyoming. The purchase price for this transaction is approximately $24.0 million in cash. The transaction remains subject to customary title diligence and purchase price adjustments for title defects. We expect to close the transaction relating to these properties on or prior to April 30, 2011. The closing of the transaction for these properties is not conditioned on the closing of the transaction relating to the seller’s Bakken formation properties.

 

•

Bakken acquisitions-Arkoma Bakken and other parties—a purchase and sale agreement, dated as of January 24, 2011, and a letter of intent, with Arkoma Bakken, LLC and other sellers with respect to undeveloped acreage located in the Bakken formation in North Dakota. These agreements provide for consideration payable in cash and in our common stock. The stock consideration will be based on a volume weighted average closing price of our common stock on the NYSE during the 15 trading days immediately prior to and including the date three trading days prior to the closing date; provided in the event such calculated price is less than $5.50, the price used will be $5.50, and in the event such calculated price is more than $6.50, the price used will be $6.50. The first purchase and sale agreement relates to the acquisition by us an undivided 87.5% of the sellers’ working interest and an 82.5% net revenue interest in approximately 7,613 undeveloped acres located in McKenzie and Dunn Counties, North Dakota (with the acquired interest representing 6,661 net acres). The aggregate purchase price for these properties is approximately $31.3 million of which approximately one-third will be paid in cash. Based on stock consideration of $20,895,423, the stock consideration would be between 3,799,168 shares (based on a value of $5.50 per share) and 3,214,681 shares (based on a value of $6.50 per share) of our common stock. The letter of intent and proposed second purchase and sale agreement relates to the acquisition of 87.5% working interest and an 80% net revenue interest in approximately 1,862 net acres in Williams County, North Dakota (with the acquired interest representing 1,629 net acres). The aggregate purchase price for these properties is currently expected to be approximately $7.3 million. Based on stock consideration of $3,828,388, the stock consideration would be between 696,071 shares of our common stock (based on a value of $5.50 per share) and 588,983 shares (based

 

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on a value of $6.50 per share). In addition to the execution of a definitive agreement for the second transaction for 1,629 net acres, the transactions remain subject to customary title diligence and purchase price adjustments for title defects, as well as other diligence. The Company expects to close the transaction relating to these properties under the first purchase and sale agreement on or before April 30, 2011. At each closing, the Company will enter into a participation agreement with a joint operating agreement designating the Company as the operator of these properties. The Company has also agreed, or will agree, to enter into a registration rights agreement with these sellers at closing relating to the resale of the shares of common stock received in this transaction. However, these sellers will agree not to sell the shares of common stock received by them for six months following the closing of these transactions.

Sale of Common Stock:

In February 2011, GMX completed an offering of 21,075,000 shares of its common stock at a price of $4.75 per share, The net proceeds to the Company were $93.6 million after underwriters’ fees. The Underwriters exercised an option to purchase an additional 1,098,518 shares from GMX that increased the net proceeds by $4.9 million after Underwriters’ fees. The Company expects to use the net proceeds, together with proceeds from a concurrent private placement of senior notes, to fund an offer to purchase up to $50.0 million of its 5.00% convertible senior notes due 2013, (ii) to repay the current outstanding balance under its secured revolving credit facility, (iii) to fund the cash portion of the purchase price of the above acquisitions of undeveloped oil and gas leases for approximately $69.5 million (assumes seller in the Niobrara acquisition above does not exercise the option to reacquire a 50% working interest in the acreage), (iv) to fund its exploration and development program and (v) for other general corporate purposes.

Issuance and Sale of Notes:

On February 9, 2011, the Company successfully completed the issuance and sale of $200,000,000 aggregate principal amount of 11.375% Senior Notes due 2019 (the “Senior Notes”). The 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 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”).

Interest on the Senior Notes will accrue from and including February 9, 2011 at a rate of 11.375% per year. Interest on the Senior Notes is payable semi-annually in arrears on February 15 and August 15 of each year, commencing on August 15, 2011. The Senior Notes mature on February 15, 2019.

The Indenture contains covenants that, among other things, limit the Company’s ability and the ability of certain of its subsidiaries to:

 

•

incur additional indebtedness;

 

•

issue preferred stock;

 

•

pay dividends or repurchase or redeem capital stock;

 

•

make certain investments;

 

•

incur liens;

 

•

enter into certain types of transactions with its affiliates;

 

•

limit dividends or other payments by the Company’s restricted subsidiaries to the Company; and

 

•

sell assets, or consolidate or merge with or into other companies.

 

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These limitations are subject to a number of important exceptions and qualifications.

Upon an Event of Default (as defined in the Indenture), the Trustee or the holders of at least 25% in aggregate principal amount of the Senior Notes then outstanding may declare the entire principal of all the Notes to be due and payable immediately.

At any time on or prior to February 15, 2014, the Company may, at our option, redeem up to 35% of the Senior Notes, including additional notes, with the proceeds of certain public offerings of our common stock at a price of 111.375% of their principal amount plus accrued interest, provided that: (i) at least 65% of the aggregate principal amount of the notes originally issued remains outstanding after the redemption; and (ii) the redemption occurs within 90 days after the closing of the related public offering.

At any time on or prior to February 15, 2015, the Company may, at its option, redeem the Senior Notes at a redemption price equal to 100% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date plus a “make-whole” premium.

On or after February 15, 2015, the Company may, at its option, redeem some or all of the Senior Notes at any time at the redemption prices set forth below, plus accrued and unpaid interest, if any, to the redemption date:

 

Year		Percentage
2015			108.531	%
2016			105.688	%
2017			102.844	%
2018 and thereafter			100.000	%

If the Company experiences certain kinds of changes of control, holders of the Senior Notes will be entitled to require us to purchase all or a portion of the Senior Notes at 101% of their principal amount, plus accrued and unpaid interest to the date of repurchase.

The purchase price for the Senior Notes and Guarantees was 96.833% of their principal amount. The net proceeds from the issuance of the Notes were approximately $187.2 million after discounts and underwriters’ fees. The Company intends to use the net proceeds of this offering (i) to fund an offer to purchase up to $50.0 million of our 5.00% convertible senior notes due 2013, (ii) to repay the current outstanding balance under its secured revolving credit facility, (iii) to fund the cash portion of the purchase price of pending acquisitions of undeveloped oil and gas leases for approximately $69.5 million, (iv) to fund the Company’s exploration and development program and (v) for other general corporate purposes.

Amended Loan Agreement:

On February 2, 2011, the Company entered into a Fifth Amended and Restated Loan Agreement among the Company, as borrower, Capital One, National Association, as administrative agent, arranger and bookrunner, BNP Paribas, as syndication agent, and the lenders named therein (the “Restated Loan Agreement”). The Restated Loan Agreement became effective after specified conditions had been satisfied, as amended on February 3, 2011, including (i) the completion of an equity offering of at least $75.0 million of common stock and an offering of senior unsecured notes in a principal amount of at least $175.0 million, on terms specified, in each case on or before February 28, 2011, (ii) the deposit of at least $50.0 million of the proceeds from the common stock and senior unsecured notes offerings in a restricted account with the agent on or before the closing date, for use solely for the purpose of retiring a portion of the Company’s convertible senior notes due 2013, such that the principal of such notes will be no more than $75.0 million within 45 days after the effective date of the Restated Loan Agreement (with such restricted account and remaining funds continuing as collateral under the Restated Loan Agreement if such debt is not retired to such outstanding balance at such time), and (iii) no

 

F-45

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advances, unpaid fees or other borrowings are outstanding under the prior loan agreement, excluding letters of credit that will be transferred to be outstanding under the Restated Loan Agreement. The Restated Loan Agreement will terminate automatically if these conditions are not satisfied by February 28, 2011.

The Restated Loan Agreement will mature on January 1, 2013; provided, that if our 5.0% convertible senior notes due 2013 have been repurchased and no longer remain outstanding, the maturity date will be extended automatically to December 31, 2013 assuming we are in compliance with all covenants under the amended secured revolving credit facility.

The Restated Loan Agreement provides for a line of credit of up to $100.0 million (the “commitment”), subject to a borrowing base (“borrowing base”). The initial borrowing base availability under the Restated Loan Agreement is $60.0 million. The amount of loans available at any one time under the Restated Loan Agreement is the lesser of the borrowing base or the amount of the commitment. The borrowing base will be subject to semi-annual redeterminations (approximately April 1 and October 1) during the term of the loan, commencing October 1, 2011, and is based on evaluations of our oil and gas reserves. The Restated Loan Agreement includes a letter of credit sublimit of up to $10.0 million.

The loans under our Restated Loan Agreement bear interest at a rate elected by the Company which is based on the prime rate, LIBOR or federal funds rate plus margins ranging from 1% to 3.50% depending on the base rate used and the amount of loans outstanding in relation to the borrowing base. We may voluntarily prepay the loans without premium or penalty. If and to the extent the loans outstanding exceed the most recently determined borrowing base, the loan excess will be mandatorily prepayable within 90 days after notice. Otherwise, any unpaid principal or interest will be due and payable at maturity. The Company is obligated to pay a facility fee equal to 0.5% per annum of the unused portion of the borrowing base, payable quarterly in arrears beginning March 31, 2011.

Loans under Restated Loan Agreement are secured by a first priority mortgage on substantially all of our oil and natural gas properties, a pledge on the Company’s ownership of equity interests in its subsidiaries, a guaranty from Endeavor Pipeline Inc. and any future subsidiaries of the Company and a security interest in certain of our and the guarantors’ assets.

NOTE P—CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The Company provides condensed consolidating financial information for its subsidiaries that are guarantors of its registered debt. The subsidiary guarantors are wholly owned and have, jointly and severally, unconditionally guaranteed on an unsecured basis the Company’s 11.375% Senor Notes. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated in right of payment to any existing or future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; and (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors who are not themselves guarantors. The Company’s subsidiary guarantors guarantee payments of principal and interest under the Company’s registered notes. The Company has not presented separate financial and narrative information for each of the subsidiary guarantors because it believes that such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the guarantees.

The following condensed consolidating financial information represents the financial information of GMX Resources Inc., its wholly owned subsidiary guarantors and its non-guarantor subsidiary, prepared on the equity basis of accounting. The non-guarantor subsidiary is included in the non-guarantor column in the tables below. The financial information may not necessarily be indicative of the financial position, results of operations or cash flows had the subsidiary guarantors operated as independent entities.

 

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Condensed Consolidating Balance Sheets

 

		December 31, 2010
		Parent				Guarantors				Non-Guarantor				Eliminations				Consolidated
		(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	1,468			$	564			$	325			$	—			$	2,357
Accounts receivable—interest owners			5,338				—				1				—				5,339
Accounts receivable—oil and natural gas revenues			6,463				366				—				—				6,829
Accounts receivable—intercompany			15,450				4,195				1,786				(21,431	)			—
Derivative instruments			19,486				—				—				—				19,486
Inventories			326				—				—				—				326
Prepaid expenses and deposits			5,532				149				86				—				5,767
Assets held for sale			1,085				16,817				8,716				—				26,618
Total current assets			55,148				22,091				10,914				(21,431	)			66,722
OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD
Properties being amortized			937,858				713				130				—				938,701
Properties not subject to amortization			39,694				—				—				—				39,694
Less accumulated depreciation, depletion and impairment			(630,632	)			—				—				—				(630,632	)
			346,920				713				130				—				347,763
PROPERTY AND EQUIPMENT, AT COST, NET			15,879				5,518				47,640				—				69,037
DERIVATIVE INSTRUMENTS			17,484				—				—				—				17,484
OTHER ASSETS			6,084				—				—				—				6,084
INVESTMENT IN SUBSIDIARIES			48,773				—				—				(48,773	)			—
TOTAL ASSETS		$	490,288			$	28,322			$	58,684			$	(70,204	)		$	507,090
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable		$	24,635			$	—			$	284			$	—				24,919
Accounts payable—intercompany			5,533				15,331				567				(21,431	)			—
Accrued expenses			32,796				116				136								33,048
Accrued interest			3,317				—				—				—				3,317
Revenue distribution payable			4,839				—				—				—				4,839
Current maturities of long-term debt			26				—				—				—				26
Total current liabilities			71,146				15,447				987				(21,431	)			66,149
LONG-TERM DEBT, LESS CURRENT MATURITIES			284,943				—				—				—				284,943
DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS			10,622				—				—				—				10,622
OTHER LIABILITIES			7,157				—				—				—				7,157
EQUITY
Total GMX equity			116,420				12,875				57,697				(70,572	)			116,420
Noncontrolling interest			—				—				—				21,799				21,799
TOTAL LIABILITIES AND EQUITY		$	490,288			$	28,322			$	58,684			$	(70,204	)		$	507,090

 

F-47

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		December 31, 2009
		Parent				Guarantors				Non-Guarantor				Eliminations				Consolidated
		(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	31,573			$	3,884			$	97			$	—			$	35,554
Accounts receivable—interest owners			1,118				115				—				—				1,233
Accounts receivable—oil and natural gas revenues			9,331				9				—				—				9,340
Accounts receivable—intercompany			14,684				2,206				1,022				(17,912	)			—
Derivative instruments			12,252				—				—				—				12,252
Inventories			326				—				—				—				326
Prepaid expenses and deposits			4,232				182				92				—				4,506
Assets held for sale			—				—				—				—				—
Total current assets			73,516				6,396				1,211				(17,912	)			63,211
OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD
Properties being amortized			756,376				28				8				—				756,412
Properties not subject to amortization			39,789				—				—				—				39,789
Less accumulated depreciation, depletion and impairment			(464,872	)			—				—				—				(464,872	)
			331,293				28				8				—				331,329
PROPERTY AND EQUIPMENT, AT COST, NET			12,175				28,690				60,890				—				101,755
DERIVATIVE INSTRUMENTS			17,292				—				—				—				17,292
OTHER ASSETS			8,484				—				—				—				8,484
INVESTMENT IN SUBSIDIARIES			59,094				—								(59,094	)			—
TOTAL ASSETS		$	501,854			$	35,114			$	62,109			$	(77,006	)		$	522,071
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable		$	18,748			$	57			$	375			$	—				19,180
Accounts payable—intercompany			3,018				14,518				376				(17,912	)			—
Accrued expenses			12,185				578				144								12,907
Accrued interest			3,361				—				—				—				3,361
Revenue distribution payable			4,434				—				—				—				4,434
Short-term derivative instruments			—				—				—				—				—
Current maturities of long-term debt			48				—				—				—				48
Total current liabilities			41,794				15,153				895				(17,912	)			39,930
LONG-TERM DEBT, LESS CURRENT MATURITIES			190,230				—				—				—				190,230
DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS			16,299				—				—				—				16,299
OTHER LIABILITIES			7,151				—				—				—				7,151
EQUITY
Total GMX (deficit) equity			246,380				19,961				61,214				(81,175	)			246,380
Noncontrolling interest			—				—				—				22,081				22,081
TOTAL LIABILITIES AND EQUITY		$	501,854			$	35,114			$	62,109			$	(77,006	)		$	522,071

 

F-48

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Condensed Consolidating Statements of Operations

 

		Parent				Guarantors				Non-Guarantor				Eliminations				Consolidated
		(In thousands)
Year Ended December 31, 2010
TOTAL REVENUES		$	95,108			$	2,164			$	8,473			$	(9,222	)		$	96,523
COSTS AND EXPENSES
Lease operating			14,850				2,540				1,831				(8,570	)			10,651
Production and severance taxes			743				—				—				—				743
Depreciation, depletion and amortization			34,958				736				2,367				—				38,061
Impairment of natural gas and oil properties and other fixed assets			132,893				4,414				6,405				—				143,712
General and administrative			25,851				1,540				380				(652	)			27,119
Total expenses			209,295				9,230				10,983				(9,222	)			220,286
Income (loss) from operations			(114,187	)			(7,066	)			(2,510	)			—				(123,763	)
NON-OPERATING INCOME (EXPENSE)
Interest expense			(18,640	)			—				(2	)			—				(18,642	)
Interest and other income (expense)			60				(17	)			(47	)			—				(4	)
Unrealized gains (losses) on derivatives			(122	)			—				—				—				(122	)
Equity Income (loss) of Subsidiaries			(12,756	)			—				—				12,756				—
Total non-operating Income (expense)			(31,458	)			(17	)			(49	)			12,756				(18,768	)
Income (loss) before income taxes			(145,645	)			(7,083	)			(2,559	)			12,756				(142,531	)
BENEFIT FOR INCOME TAXES			4,239				—				—				—				4,239
NET INCOME (LOSS)			(141,406	)			(7,083	)			(2,559	)			12,756				(138,292	)
Net income attributable to noncontrolling interest			—				—				—				3,114				3,114
NET LOSS APPLICABLE TO GMX			(141,406	)			(7,083	)			(2,559	)			9,642				(141,406	)
Preferred stock dividends			4,633				—				—				—				4,633
NET LOSS APPLICABLE TO COMMON SHAREHOLDERS			(146,039	)			(7,083	)			(2,559	)			9,642				(146,039	)
Year Ended December 31, 2009
TOTAL REVENUES		$	93,657			$	9,010			$	1,022			$	(9,395	)		$	94,294
COSTS AND EXPENSES
Lease operating			14,628				2,153				341				(5,346	)			11,776
Production and severance taxes			(930	)			—				—				—				(930	)
Depreciation, depletion and amortization			25,412				6,415				374				(1,195	)			31,006
Impairment of natural gas and oil properties and other fixed assets			188,150				—				—				—				188,150
General and administrative			20,166				3,988				90				(2,854	)			21,390
Total expenses			247,426				12,556				805				(9,395	)			251,392
Income (loss) from operations			(153,769	)			(3,546	)			217				—				(157,098	)
NON-OPERATING INCOME (EXPENSE)
Interest expense			(16,747	)			—				(1	)			—				(16,748	)
Loss on extinguishment of debt			(4,976	)			—				—				—				(4,976	)
Interest and other income (expense)			72				—				—				—				72
Unrealized gains (losses) on derivatives			(2,370	)			—				—				—				(2,370	)
Equity Income (loss) of Subsidiaries			(3,503	)			—				—				3,503				—
Total non-operating income (expenses)			(27,524	)			—				(1	)			3,503				(24,022	)
Income (loss) before income taxes			(181,293	)			(3,546	)			216				3,503				(181,120	)
BENEFIT FOR INCOME TAXES			33				—				—				—				33
NET INCOME (LOSS)			(181,260	)			(3,546	)			216				3,503				(181,087	)
Net income attributable to noncontrolling interest			—				—				—				173				173
NET INCOME (LOSS) APPLICABLE TO GMX			(181,260	)			(3,546	)			216				3,330				(181,260	)
Preferred stock dividends			4,625				—				—				—				4,625
NET INCOME (LOSS) APPLICABLE TO COMMON SHAREHOLDERS			(185,885	)			(3,546	)			216				3,330				(185,885	)

 

F-49

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		Parent				Guarantors				Non-Guarantor				Eliminations				Consolidated
		(In thousands)
Year Ended December 31, 2008
TOTAL REVENUES		$	125,736			$	19,243			$	—			$	(19,243	)		$	125,736
COSTS AND EXPENSES
Lease operating			16,938				2,449				—				(4,286	)			15,101
Production and severance taxes			5,306				—				—				—				5,306
Depreciation, depletion and amortization			27,900				7,379				—				(3,535	)			31,744
Impairment of natural gas and oil properties and other fixed assets			192,650				—				—				—				192,650
General and administrative			16,647				11,596				—				(11,344	)			16,899
Total expenses			259,441				21,424				—				(19,165	)			261,700
Income (loss) from operations			(133,705	)			(2,181	)			—				(78	)			(135,964	)
NON-OPERATING INCOME (EXPENSE)
Interest expense			(14,105	)			—				—				—				(14,105	)
Interest and other income (expense)			285				(77	)			—				77				285
Unrealized gains (losses) on derivatives			(354	)			—				—				—				(354	)
Equity Income (loss) of Subsidiaries			(2,258	)			—				—				2,258				—
Total non-operating income (expense)			(16,432	)			(77	)			—				2,335				(14,174	)
Income (loss) before income taxes			(150,137	)			(2,258	)			—				2,257				(150,138	)
BENEFIT FOR INCOME TAXES			26,217				—				—				—				26,217
NET LOSS			(123,920	)			(2,258	)			—				2,257				(123,921	)
Net income attributable to noncontrolling interest			—				—				—				—				—
NET LOSS APPLICABLE TO GMX			(123,920	)			(2,258	)			—				2,257				(123,921	)
Preferred stock dividends			4,625				—				—				—				4,625
NET INCOME (LOSS) APPLICABLE TO COMMON SHAREHOLDERS			(128,545	)			(2,258	)			—				2,257				(128,546	)

 

F-50

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Condensed Consolidating Statements of Cash Flows

 

		Parent				Guarantors				Non-Guarantor				Eliminations				Consolidated
		(In thousands)
Year Ended December 31, 2010
Net cash provided by (used in) operating activities		$	54,708			$	(1,567	)		$	5,594				—			$	58,735
Net cash provided by (used in) investing activities			(171,470	)			(1,753	)			(2,777	)			—				(176,000	)
Net cash provided by (used in) financing activities			86,657				—				(2,589	)			—				84,068
Net increase (decrease) in cash			(30,105	)			(3,320	)			228				—				(33,197	)
Cash and cash equivalents at beginning of period			31,573				3,884				97				—				35,554
Cash and cash equivalents at end of period		$	1,468			$	564			$	325			$	—			$	2,357
Year Ended December 31, 2009
Net cash provided by (used in) operating activities		$	28,242			$	20,877			$	371				—			$	49,490
Net cash provided by (used in) investing activities			(159,930	)			(20,920	)			(474	)			—				(181,324	)
Net cash provided by (used in) financing activities			160,472				—				200				—				160,672
Net increase (decrease) in cash			28,784				(43	)			97				—				28,838
Cash and cash equivalents at beginning of period			2,789				3,927				—				—				6,716
Cash and cash equivalents at end of period		$	31,573			$	3,884			$	97			$	—			$	35,554
Year Ended December 31, 2008
Net cash provided by (used in) operating activities		$	44,635			$	38,602				—				—			$	83,237
Net cash provided by (used in) investing activities			(279,281	)			(39,079	)			—				—				(318,360	)
Net cash provided by (used in) financing activities			235,932				—				—				—				235,932
Net increase (decrease) in cash			1,286				(477	)			—				—				809
Cash and cash equivalents at beginning of period			1,503				4,404				—				—				5,907
Cash and cash equivalents at end of period		$	2,789			$	3,927			$	—			$	—			$	6,716

 

F-51