10-Q 1 gmxr-2012930x10q.htm FORM 10-Q GMXR-2012.9.30-10Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
______________________________________ 
FORM 10-Q
 ______________________________________ 
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended September 30, 2012
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from              to             
Commission File Number 001-32977
 ______________________________________ 
GMX RESOURCES INC.
(Exact name of registrant as specified in its charter)
______________________________________ 
Oklahoma
 
73-1534474
(State or other jurisdiction of
incorporation or organization)
 
(IRS Employer
Identification No.)
 
 
One Benham Place, 9400 North Broadway, Suite 600
Oklahoma City, Oklahoma
 
73114
(Address of principal executive offices)
 
(Zip Code)
(Registrants’ telephone number, including area code): (405) 600-0711
______________________________________ 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  o 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  o 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer or a smaller reporting company. See the definitions of “accelerated filer,” “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Check one:
Large accelerated filer
 
o
Accelerated filer
 
x
Non-accelerated filer
 
o  (Do not check if a smaller reporting company)
Smaller reporting company
 
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)    Yes  o    No  x
The number of shares outstanding of the registrant’s common stock as of November 7, 2012 was 82,661,295, which included 2,364,375 shares under a share loan which will be returned to the registrant upon conversion of certain outstanding convertible notes.



GMX Resources Inc.
Form 10-Q
For the Quarter Ended September 30, 2012
TABLE OF CONTENTS
 


2


PART I. FINANCIAL INFORMATION
ITEM 1.
Financial Statements.
GMX Resources Inc. and Subsidiaries
Consolidated Balance Sheets
 
September 30, 2012
 
December 31, 2011
ASSETS
(Unaudited)
 
 
CURRENT ASSETS:
(In thousands, except share data)
Cash and cash equivalents
$
15,535

 
$
102,493

Restricted cash
2,325

 
4,325

Accounts receivable – interest owners
4,813

 
8,607

Accounts receivable – oil and natural gas revenues, net
4,629

 
7,082

Derivative instruments
918

 

Inventories
326

 
326

Prepaid expenses and deposits
1,058

 
2,655

Assets held for sale
410

 
2,045

Total current assets
30,014

 
127,533

OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD
 
 
 
Properties being amortized
1,136,682

 
1,062,801

Properties not subject to amortization
158,574

 
147,224

Less accumulated depreciation, depletion, and impairment
(1,053,445
)
 
(871,346
)
 
241,811

 
338,679

PROPERTY AND EQUIPMENT, AT COST, NET
61,836

 
65,858

DERIVATIVE INSTRUMENTS
828

 

OTHER ASSETS
8,659

 
10,131

TOTAL ASSETS
$
343,148

 
$
542,201

LIABILITIES AND EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable
$
10,273

 
$
13,550

Accrued expenses
21,514

 
17,835

Accrued interest
13,872

 
3,256

Revenue distributions payable
4,245

 
5,980

Short-term derivative instruments
1,390

 

Current maturities of long-term debt
26,876

 
26

Total current liabilities
78,170

 
40,647

LONG-TERM DEBT, LESS CURRENT MATURITIES
380,528

 
426,805

DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS
402

 

OTHER LIABILITIES
8,543

 
7,476

EQUITY:
 
 
 
Preferred stock, par value $.001 per share, 10,000,000 shares authorized:
 
 
 
Series A Junior Participating Preferred Stock, 25,000 shares authorized, none issued and outstanding

 

9.25% Series B Cumulative Preferred Stock, 6,000,000 shares authorized, 3,176,734 shares issued and outstanding as of September 30, 2012 and December 31, 2011 (aggregate liquidation preference $79,418 as of September 30, 2012 and December 31, 2011)
3

 
3

Common stock, par value $.001 per share – 250,000,000 shares authorized, 82,082,972 shares issued and outstanding as of September 30, 2012 and 63,085,432 shares issued and outstanding as of December 31, 2011
82

 
63

Additional paid-in capital
716,278

 
690,986

Accumulated deficit
(856,029
)
 
(649,341
)
Accumulated other comprehensive income, net of taxes
5,142

 
14,029

Total GMX Resources’ equity
(134,524
)
 
55,740

Noncontrolling interest
10,029

 
11,533

Total equity
(124,495
)
 
67,273

TOTAL LIABILITIES AND EQUITY
$
343,148

 
$
542,201

See accompanying notes to consolidated financial statements.

3


GMX Resources Inc. and Subsidiaries
Consolidated Statements of Operations
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012
 
2011
 
2012
 
2011
 
(In thousands, except share and per share data)
OIL AND GAS SALES
$
14,591

 
$
28,364

 
$
48,275

 
$
90,629

EXPENSES:
 
 
 
 
 
 
 
Lease operations
3,259

 
3,194

 
9,255

 
8,965

Production and severance taxes
499

 
310

 
818

 
859

Depreciation, depletion, and amortization
5,935

 
13,989

 
20,374

 
40,083

Impairment of oil and natural gas properties and assets held for sale
45,506

 
62,550

 
166,196

 
127,731

General and administrative
5,368

 
7,609

 
19,165

 
22,284

Total expenses
60,567

 
87,652

 
215,808

 
199,922

Loss from operations
(45,976
)
 
(59,288
)
 
(167,533
)
 
(109,293
)
NON-OPERATING INCOME (EXPENSES):
 
 
 
 
 
 
 
Interest expense
(10,065
)
 
(7,680
)
 
(30,890
)
 
(23,534
)
Gain (loss) on conversion/extinguishment of debt
1,502

 

 
5,114

 
(176
)
Interest and other income
23

 
9

 
131

 
291

Unrealized gain (loss) on derivatives
(1,324
)
 
(1,338
)
 
(545
)
 
3,654

Total non-operating expense
(9,864
)
 
(9,009
)
 
(26,190
)
 
(19,765
)
Loss before income taxes
(55,840
)
 
(68,297
)
 
(193,723
)
 
(129,058
)
INCOME TAX (PROVISION) BENEFIT
(1,389
)
 
2,386

 
(4,694
)
 
(481
)
NET LOSS
(57,229
)
 
(65,911
)
 
(198,417
)
 
(129,539
)
Net income attributable to noncontrolling interest
890

 
1,181

 
2,761

 
4,339

NET LOSS APPLICABLE TO GMX RESOURCES
(58,119
)
 
(67,092
)
 
(201,178
)
 
(133,878
)
Preferred stock dividends
1,837

 
1,837

 
5,510

 
4,884

NET LOSS APPLICABLE TO COMMON SHAREHOLDERS
$
(59,956
)
 
$
(68,929
)
 
$
(206,688
)
 
$
(138,762
)
LOSS PER SHARE – Basic
$
(0.82
)
 
$
(1.21
)
 
$
(3.02
)
 
$
(2.69
)
LOSS PER SHARE – Diluted
$
(0.82
)
 
$
(1.21
)
 
$
(3.02
)
 
$
(2.69
)
WEIGHTED AVERAGE COMMON SHARES – Basic
73,453,500

 
56,842,336

 
68,386,226

 
51,629,035

WEIGHTED AVERAGE COMMON SHARES – Diluted
73,453,500

 
56,842,336

 
68,386,226

 
51,629,035

See accompanying notes to consolidated financial statements.

4


GMX Resources Inc. and Subsidiaries
Consolidated Statements of Comprehensive Income
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012
 
2011
 
2012
 
2011
 
(In thousands)
Net loss
$
(57,229
)
 
$
(65,911
)
 
$
(198,417
)
 
$
(129,539
)
Other comprehensive loss, net of income tax:
 
 
 
 
 
 
 
Change in fair value of derivative instruments, net of income tax of $0, $3,974, $0 and $3,976, respectively

 
7,715

 

 
7,718

Reclassification of gain on settled contracts, net of income taxes of ($1,351), ($1,588), ($4,578) and ($4,456), respectively
(2,622
)
 
(3,083
)
 
(8,887
)
 
(8,651
)
Comprehensive loss
(59,851
)
 
(61,279
)
 
(207,304
)
 
(130,472
)
Comprehensive income attributable to the noncontrolling interest
890

 
1,181

 
2,761

 
4,339

Comprehensive loss attributable to GMX shareholders
$
(60,741
)
 
$
(62,460
)
 
$
(210,065
)
 
$
(134,811
)
See accompanying notes to consolidated financial statements.
 

5


GMX Resources Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(Unaudited)
 
Nine Months Ended
 
September 30,
 
2012
 
2011
CASH FLOWS DUE TO OPERATING ACTIVITIES
(In thousands)
Net loss
$
(198,417
)
 
$
(129,539
)
Depreciation, depletion, and amortization
20,374

 
40,083

Impairment of oil and natural gas properties and assets held for sale
166,196

 
127,731

Deferred income taxes
4,578

 
481

Non-cash compensation expense
3,196

 
2,907

(Gain) loss on conversion/extinguishment of debt
(5,114
)
 
176

Non-cash interest expense
6,129

 
6,978

Non-cash change in fair value of derivative financial instruments
545

 
(2,305
)
Non-cash derivative gain in oil and gas sales
(13,466
)
 

Other
(28
)
 
(49
)
Decrease (increase) in:
 
 
 
Accounts receivable
6,171

 
1,131

Inventory and prepaid expenses
1,486

 
(3,453
)
Increase (decrease) in:
 
 
 
Accounts payable and accrued liabilities
4,766

 
1,849

Revenue distributions payable
(1,845
)
 
2,092

Net cash (used in) provided by operating activities
(5,429
)
 
48,082

CASH FLOWS DUE TO INVESTING ACTIVITIES
 
 
 
Purchase, exploration and development of oil and natural gas properties
(75,580
)
 
(240,113
)
Proceeds from sale of oil and natural gas properties, property, equipment and assets held for sale
1,765

 
13,560

Purchase of short term investments
23

 

Purchase of property and equipment
(483
)
 
(2,061
)
Cash settlement of hedges

 
2,673

Other investing
2,000

 

Net cash used in investing activities
(72,275
)
 
(225,941
)
CASH FLOWS DUE TO FINANCING ACTIVITIES
 
 
 
Borrowings on revolving bank credit facility

 
61,750

Repayments of long-term debt
(33
)
 
(173,461
)
Proceeds from issuance of long-term debt

 
193,666

Proceeds from sale of common stock

 
105,324

Proceeds from sale of preferred stock

 
25,809

Dividends paid on Series B preferred stock
(3,673
)
 
(4,884
)
Fees paid related to financing activities
(1,283
)
 
(16,796
)
Contributions from non-controlling interest member

 
408

Distributions to non-controlling interest member
(4,265
)
 
(13,086
)
Net cash (used in) provided by financing activities
(9,254
)
 
178,730

NET (DECREASE) INCREASE IN CASH
(86,958
)
 
871

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
102,493

 
2,357

CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
15,535

 
$
3,228

SUPPLEMENTAL CASH FLOW DISCLOSURE
 
 
 
CASH PAID DURING THE PERIOD FOR:
 
 
 
INTEREST, Net of amounts capitalized
$
13,120

 
$
14,653

INCOME TAXES, Paid
$
116

 
$
1

NON-CASH INVESTING AND FINANCING ACTIVITIES
 
 
 
Debt extinguished with common stock
$
26,207

 
$

Debt extinguished in debt exchange
$
11,414

 
$

Additions to oil and natural gas properties in exchange for common stock
$

 
$
31,612

Decrease in accounts payable for property additions
$
9,053

 
$
21,514

Interest paid in the form of additional notes ("PIK Election")
$
5,102

 
$

See accompanying notes to consolidated financial statements.

6


GMX Resources Inc. and Subsidiaries
Condensed Notes to the Consolidated Interim Financial Statements
(Unaudited)

NOTE A – NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Business
GMX Resources Inc. (collectively with its subsidiaries, “GMX” the “Company”, “we,” “us” and “our”) is an independent oil and natural gas exploration and production company with a portfolio of leasehold acreage in multiple resource plays that allows the Company flexibility to deploy capital based on a variety of economic and technical factors, including commodity prices (including differentials applicable to the basin), well costs, service availability, and take-away capacity.
Prior to 2011, the Company focused on the development of the hydrocarbon formations in East Texas including the Cotton Valley Sands (“CVS”) layer in the Schuler formation and the Upper, Middle and Haynesville/Lower Bossier layers of the Bossier formation (“H/B”), in the Sabine Uplift of the Carthage, North Field primarily located in Harrison and Panola counties of East Texas (previously designated as our “primary development area”). On October 24, 2012, the Company consummated its sale of certain CVS properties. See Note I, Subsequent Events.
In late 2010, we made a strategic decision to expand our asset base and development activities into other basins in order to diversify our significant concentration in natural gas to a multiple basin and commodity strategy with more liquid hydrocarbon opportunities. In the first half of 2011, we acquired core positions in over 75,000 undeveloped net acres in two of the leading oil resource plays in the U.S.: the Williston Basin of North Dakota/Montana, targeting the Bakken/Three Forks Formation; and in the oil window of the Denver Julesburg Basin (the “DJ Basin”) of Wyoming, targeting the emerging Niobrara Formation. We believe the oil production from the liquids-rich Bakken and Niobrara acreage will enable us to generate higher cash flow growth to fund our capital expenditure program. The Company is utilizing our expertise in H/B shale horizontal drilling to explore and develop these oil resources.
We have three subsidiaries: Diamond Blue Drilling Co. (“Diamond Blue”), which sold its assets in 2011 and is not active, Endeavor Pipeline Inc. (“Endeavor Pipeline”), which operates our water supply and salt water disposal systems in our East Texas development area, and Endeavor Gathering, LLC (“Endeavor Gathering”), which owns the natural gas gathering system and related equipment operated by Endeavor Pipeline. Kinder Morgan Endeavor LLC (“KME”) owns a 40% membership interest in Endeavor Gathering.
Basis of Presentation
The accompanying unaudited consolidated financial statements and condensed notes thereto of GMX have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted. The accompanying consolidated financial statements and notes thereto should be read in conjunction with the audited consolidated financial statements and notes thereto included in GMX’s 2011 Annual Report on Form 10-K (“2011 Form 10-K”).
In the opinion of GMX’s management, all adjustments (all of which are normal and recurring) have been made which are necessary to fairly state the unaudited consolidated balance sheet of GMX as of September 30, 2012, and the results of its operations and cash flows for the three and nine months ended September 30, 2012 and 2011.
Liquidity and Management's Plans
At September 30, 2012, the Company had a working capital deficit of $48.2 million, which included $17.9 million in cash and restricted cash in current assets and $26.9 million in current liabilities related to the 5.00% Convertible Senior Notes due February 2013 ("5.00% Convertible Notes").
The Company has reduced the original principal amount of the 5.00% Convertible Notes by $45.7 million since December 31, 2011, which includes a reduction of $24.9 million in the third quarter 2012 related to a debt-for-debt exchange discussed in Note B below. See Note I - Subsequent Events in regards to the Company's agreements with certain holders of the Company's existing Senior Secured Notes due 2017 to provide financing commitments for use to retire the remaining $27.1 million principal amount of the 5.00% Convertible Notes outstanding as of September 30, 2012, by issuing $30.0 million principal amount of new Senior Secured Notes due 2017.

7


The Company is also focused on increasing its liquidity to fund its ongoing Bakken oil drilling program. On October 24, 2012, the Company sold to a private third party a portion of its Cotton Valley Sand liquids rich natural gas properties located in East Texas and Louisiana for approximately $66.7 million, net of revenues and expenses for the month of September 2012 and selling costs. The asset sale includes the Company's interests in specified operated and non-operated properties in the Cotton Valley Sands and shallow rights located in East Texas and Louisiana.
On October 10, 2012, the Company announced that it will hold a special meeting of the shareholders on November 29, 2012 to seek approval on granting the Board of Directors the discretionary authority to effect a reverse stock split. Effecting the reverse stock split would among other things, help the Company to meet certain listing requirements of the New York Stock Exchange, appeal to a broader range of investors to generate greater investor interest in the Company and improve the perception of the Company's common stock as an investment security.
We are also considering a Bakken joint venture and/or a partial sale or joint venture on our 40,000 acres in the Niobrara, potentially increasing the Company's liquidity position for more oil development. The Company has historically relied on asset sales, joint ventures and the capital markets to fund its capital needs. Management believes that these actions will enable the Company to meet its liquidity requirements through the next twelve months.
Earnings Per Share
Basic earnings (loss) per common share is computed by dividing the net income (loss) applicable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings (loss) per common share is calculated in the same manner, but also considers the impact to net income (loss) and common shares for the potential dilution from our convertible notes, outstanding stock options and non-vested restricted stock awards. Because the Company was in a loss position for the three and nine months ended September 30, 2012 and 2011, the instruments mentioned above would decrease diluted loss per share, which would result in anti-dilutive instruments. Therefore, there were no dilutive shares for the three and nine months ended September 30, 2012 and 2011.
Oil and Natural Gas Properties
The Company follows the full cost method of accounting for its oil and natural gas properties and activities. Accordingly, the Company capitalizes all costs incurred in connection with the acquisition, exploration and development of oil and natural gas properties. The Company capitalizes internal costs that can be directly identified with exploration and development activities, but does not include any costs related to production, general corporate overhead, or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and gas wells, including salaries and benefits and other internal costs directly attributable to these activities. Also included in oil and natural gas properties are tubular and other lease and well equipment of $3.5 million as of September 30, 2012 and $3.8 million as of December 31, 2011, that have not been placed in service but for which we plan to utilize in our ongoing exploration and development activities.
Capitalized costs are subject to a “ceiling test,” which limits the net book value of oil and natural gas properties less related deferred income taxes to the estimated after-tax future net revenues discounted at a 10-percent rate. The cost of unproved properties is added to the future net revenues less income tax effects. Future net revenues are calculated using prices that represent the average of the first day of the month price for the 12-months ending at the end of the period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges.
The primary factors impacting the full cost method ceiling test are expenditures added to the full cost pool, reserve levels, natural gas and oil prices and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value is generally written off as an expense. Natural gas represents 85% of the Company’s total production for the three months ended September 30, 2012, and as a result, a decrease in natural gas prices can significantly impact the Company’s ceiling test. During the first nine months of 2012, the 12-month average of the first day of the month natural gas price decreased 32% from $4.12 per million British thermal units (MMbtu) at December 31, 2011 to $2.82 per MMbtu at September 30, 2012. As a result of the Company’s quarterly ceiling test, the Company recorded impairment expense related to oil and gas properties of $45.5 million and $166.3 million for the three and nine months ended September 30, 2012, respectively.

8


Assets held for sale are carried on the balance sheet at their carrying value or fair value less cost to sell, whichever is less. Subsequent increases in fair value less cost to sell will be recognized as a gain, but not in excess of the cumulative loss previously recognized. In April 2012, the Company sold a compressor, which was included in assets held for sale as of March 31, 2012, for $1.5 million and a gain of $0.1 million was recognized on that sale. The remaining assets held for sale of $0.4 million as of September 30, 2012 consist of valves and pipe, which the Company is actively marketing.
Recent Accounting Standards
In June 2011, the FASB issued ASU No. 2011-05, Presentation of Comprehensive Income. The issuance of ASU 2011-5 is intended to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The guidance in ASU 2011-5 supersedes the presentation options in ASC Topic 220 and facilitates convergence of U.S. generally accepted accounting principles and International Financial Reporting Standards ("IFRS") by eliminating the option to present components of other comprehensive income as part of the statement of changes in shareholders' equity and requiring that all non-owner changes in shareholders' equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This guidance is effective during the interim and annual periods beginning after December 15, 2011. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements.
In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S GAAP and IFRS. This amendment of the FASB Accounting Standards Codification is to ensure that fair value has the same meaning in U.S. GAAP and IFRS and that their respective fair value measurement and disclosure requirements are the same. This guidance is effective during the interim and annual periods beginning after December 15, 2011. The adoption of the guidance did not have any material effect on the Company’s financial statements.
NOTE B – LONG-TERM DEBT
The table below presents the carrying amounts and approximate fair values of our debt obligations. The approximate fair values of our convertible and other debt securities are determined based on market quotes from independent third party brokers as they are actively traded in an established market.
 
 
September 30, 2012
 
December 31, 2011
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
 
 
 
(in thousands)
 
 
5.00% Convertible Senior Notes due February 2013
$
26,851

 
$
18,955

 
$
70,757

 
$
46,560

4.50% Convertible Senior Notes due May 2015
44,383

 
19,318

 
77,457

 
41,400

Senior Secured Notes due December 2017
281,535

 
271,262

 
275,411

 
283,475

Senior Secured Second-Priority Notes due March 2018
51,458

 
51,458

 

 

11.375% Senior Notes due February 2019
1,916

 
1,290

 
1,912

 
1,300

Joint venture financing(1)
1,261

 
1,261

 
1,294

 
1,294

Total
$
407,404

 
$
363,544

 
$
426,831

 
$
374,029

 __________________
(1)
Non-recourse, no interest rate
5.00% Convertible Senior Notes
As of September 30, 2012 and December 31, 2011, the net carrying amount of our 5.00% Convertible Notes was as follows (amounts in thousands):
 
September 30, 2012
 
December 31, 2011
Principal amount
$
27,079

 
$
72,750

Less: Unamortized debt discount
(228
)
 
(1,993
)
Carrying amount
$
26,851

 
$
70,757

The 5.00% Convertible Notes bear interest at a rate of 5.00% per year, payable semi-annually in arrears on February 1 and August 1 of each year, beginning August 1, 2008. As a result of the amortization of the debt discount through non-cash

9


interest expense, the effective interest rate on the 5.00% Convertible Notes is 7.63% per annum. The amount of the cash interest expense recognized with respect to the 5.00% contractual interest coupon for the three and nine months ended September 30, 2012 was $0.6 million and $2.2 million, respectively, and $0.9 million and $3.2 million for the three and nine months ended September 30, 2011, respectively. The amount of non-cash interest expense related to the amortization of the debt discount and amortization of the transaction costs for the three and nine months ended September 30, 2012 was $0.4 million and $1.4 million, respectively, and $0.6 million and $2.0 million for the three and nine months ended September 30, 2011, respectively.
As of September 30, 2012, the unamortized debt discount is expected to be amortized into earnings over 0.3 years. The carrying value of the equity component of the 5.00% Convertible Notes was $3.9 million as of September 30, 2012. As of September 30, 2012 and December 31, 2011, unamortized debt issue costs were approximately $0.1 million and $0.6 million, respectively.
As of September 30, 2012, the balance of the 5.00% Convertible Notes was classified as a current liability due to the maturity date of February 1, 2013. During the first six months of 2012, we entered into separate exchange agreements with various holders of our 5.00% Convertible Notes. Pursuant to these agreements, as consideration for the surrender by the holders of $20.8 million aggregate principal amount of the 5.00% Convertible Notes, we issued to the holders an aggregate of 11,271,510 shares of our common stock. As a result, the Company has recorded a net gain of approximately $3.8 million, including a loss of approximately $15.4 million for the early conversion offer and a gain of approximately $19.2 million for the cancellation of indebtedness of such 5.00% Convertible Notes.
On September 19, 2012, the Company completed an exchange of $24.9 million of the 5.00% Convertible Notes for $24.9 million of newly issued Senior Secured Second-Priority Notes and 7,176,384 shares of our common stock. The exchange transaction was accounted for as an extinguishment of debt under FASB Accounting Standards Codification 470-50. As a result of the transaction, the Company recorded a loss of $5.8 million.
See Note I - Subsequent Events in regards to the Company's agreements with certain holders of the Company's existing Senior Secured Notes due 2017 to provide financing commitments for use to retire the remaining $27.1 million principal amount of the 5.00% Convertible Notes outstanding as of September 30, 2012, by issuing $30.0 million principal amount of new Senior Secured Notes due 2017.
4.50% Convertible Senior Notes
As of September 30, 2012 and December 31, 2011, the net carrying amount of our 4.50% Convertible Senior Notes due 2015 (the "4.50% Convertible Notes") was as follows (amounts in thousands):
 
September 30, 2012
 
December 31, 2011
Principal amount
$
48,296

 
$
86,250

Less: Unamortized debt discount
(3,913
)
 
(8,793
)
Carrying amount
$
44,383

 
$
77,457

The 4.50% Convertible Notes bear interest at a rate of 4.50% per year, payable semiannually in arrears on November 1 and May 1 of each year, beginning May 1, 2010. As a result of the amortization of the debt discount through non-cash interest expense, the effective interest rate on the 4.50% Convertible Notes is 8.10% per annum. The amount of the cash interest expense recognized with respect to the 4.50% contractual interest coupon for the three and nine months ended September 30, 2012 was $0.9 million and $2.9 million, respectively, and $1.0 million and $3.0 million for the three and nine months ended September 30, 2011, respectively. The amount of non-cash interest expense related to the amortization of the debt discount and transaction costs for the three and nine months ended September 30, 2012 was $0.7 million and $2.1 million, respectively, and $0.7 million and $2.0 million for the three and nine months ended September 30, 2011, respectively. As of September 30, 2012, the unamortized discount is expected to be amortized into earnings over 2.6 years. The carrying value of the equity component of the 4.50% Convertible Notes was $8.4 million as of September 30, 2012.
On September 19, 2012, the Company completed an exchange of $38.0 million of the 4.50% Convertible Notes for $26.5 million of newly issued Senior Secured Second-Priority Notes. The holders of the 4.50% Convertible Notes who participated in the exchange received $700 of Senior Secured Second-Priority Notes for every $1,000 of 4.50% Convertible Notes exchanged. The exchange transaction was accounted for as an extinguishment of debt under FASB Accounting Standards Codification 470-50. As a result of the transaction, the Company recorded a gain of $7.3 million.

10


Senior Secured Notes
On December 19, 2011, the Company executed an indenture (the “Senior Secured Notes Indenture”), among the Company, the guarantors party thereto and U.S. Bank National Association, as trustee. The Company issued $283.5 aggregate principal amount of Senior Secured Notes due 2017 (the “Senior Secured Notes”) pursuant to the Senior Secured Notes Indenture. The Senior Secured Notes are fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by each of the Company’s existing and future domestic restricted subsidiaries (the “Senior Secured Notes Guarantors”). All of the Company’s existing subsidiaries other than Endeavor Gathering, LLC are domestic restricted subsidiaries and Senior Secured Notes Guarantors. As of September 30, 2012 and December 31, 2011, the net carrying amount of the Senior Secured Notes was as follows (amounts in thousands):
 
September 30, 2012
 
December 31, 2011
Principal amount
$
288,577

 
$
283,475

Less: Unamortized debt discount
(7,042
)
 
(8,064
)
Carrying amount
$
281,535

 
$
275,411

The Senior Secured Notes bear interest at a rate of 11.00% per year, payable semiannually on June 1 and December 1 of each year, beginning June 1, 2012. The Senior Secured Notes Indenture provides the Company the option to pay a portion of the interest due in the form of additional notes ("PIK Election"), which allows for a 9.00% cash interest payment along with additional Senior Secured Notes of 4.00% resulting in an annual interest rate of 13.00%. For the June 1, 2012 interest payment, the Company elected the PIK Election and paid cash interest of $11.5 million and issued an additional $5.1 million of Senior Secured Notes. The Company has elected the PIK election for the December 1, 2012 interest payment. As a result of the amortization of the debt discount through non-cash interest expense, the effective interest rate on the Senior Secured Notes is 11.68% per annum if the cash only option is elected. If the PIK option is elected, the effective interest rate on the Senior Secured Notes is 13.52% per annum. The amount of the interest expense recognized with respect to the 13.00% PIK Election interest coupon for the three and nine months ended September 30, 2012 was $9.4 million and $28.1 million, respectively. The amount of non-cash interest expense for the three and nine months ended September 30, 2012 related to the amortization of the debt discount and transaction costs was $0.3 million and $0.8 million, respectively. As of September 30, 2012, the unamortized discount is expected to be amortized into earnings over 5.2 years.
Senior Secured Second-Priority Notes
On September 19, 2012, the Company exchanged $24.9 million aggregate principal amount of 5.00% Convertible Notes and $38.0 million aggregate principal amount of 4.50% Convertible Notes for a total of $51.5 million of newly issued Senior Secured Second-Priority Notes and, in connection with the exchange of the 5.00% Convertible Notes, 7,176,384 shares of common stock. The Senior Secured Second-Priority Notes will mature on March 2, 2018.
Interest is paid quarterly on December 2, March 2, June 2 and September 2, commencing March 2, 2013. The Company has the option to pay interest in cash or common stock through September 19, 2014. Subsequent to September 19, 2014, the option to pay interest in common stock expires and all interest payments must be paid in cash only. Interest on the Senior Secured Second-Priority Notes accrues at an interest rate of 9.00% per annum if the Company chooses to pay the interest in cash or 12.00% per annum if the Company chooses to pay the interest in common stock.
The Senior Secured Second-Priority Notes are secured by second-priority perfected liens on all of the assets and properties owned or acquired by the Company.
The Senior Secured Second-Priority Notes restricts, among other things, the Company’s and its restricted subsidiaries' ability to:
incur or guarantee additional indebtedness or issue certain preferred stock;
pay dividends or make other distributions;
issue capital stock of our restricted subsidiaries;
transfer or sell assets, including the capital stock of our restricted subsidiaries;
make certain investments or acquisitions;
grant liens on our assets;

11


merge, consolidate or transfer all or substantially all of our assets.
As of September 30, 2012, the net carrying amount of the Senior Secured Second-Priority Notes equaled the principal amount of $51.5 million. The stated interest rates of the Senior Secured Second-Priority Notes reflected the market interest rates at the time of the exchange, so no premium or discount was recorded. The deferred direct costs incurred related to this transaction were $1.7 million as of September 30, 2012, and is amortized over the life of the Senior-Secured Second Priority Notes.
11.375% Senior Notes
On February 9, 2011, the Company successfully completed the issuance and sale of $200 million aggregate principal amount of 11.375% Senior Notes due 2019 (the “11.375% Senior Notes”). The 11.375% Senior Notes are jointly and severally, and unconditionally, guaranteed (the “guarantees”) on a senior unsecured basis initially by two of our wholly-owned subsidiaries, and all of our future subsidiaries other than immaterial subsidiaries (the “Senior Notes Guarantors”). The 11.375% Senior Notes and the guarantees were issued pursuant to an indenture dated as of February 9, 2011 (the “Indenture”), by and among the Company, the Senior Notes Guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., a national banking association, as trustee.
In December 2011, the Company entered into an exchange transaction related to the new Senior Secured Notes mentioned below. Approximately $198 million of the 11.375% Senior Notes were exchanged to new Senior Secured Notes. As of September 30, 2012 and December 31, 2011, the net carrying amount of the 11.375% Senior Notes was as follows (amounts in thousands):
 
September 30, 2012
 
December 31, 2011
Principal amount
$
1,970

 
$
1,970

Less: Unamortized debt discount
(54
)
 
(58
)
Carrying amount
$
1,916

 
$
1,912

The 11.375% senior notes bear interest at a rate of 11.375% per year, payable semi-annually in arrears on February 15 and August 15 of each year, beginning August 15, 2011. As a result of the amortization of the debt discount through non-cash interest expense, the effective interest rate on the 11.375% senior notes is 12.94% per annum. The amount of the cash interest expense recognized with respect to the 11.375% contractual interest coupon for the three and nine months ended September 30, 2012 was $56,000 and $168,000, respectively, and $5.7 million and $14.7 million for the three and nine months ended September 30, 2011, respectively. The amount of non-cash interest expense related to the amortization of the debt discount and transaction costs for the three and nine months ended September 30, 2012 was $2,700 and $7,800, respectively, and $0.3 million and $0.9 million for the three and nine months ended September 30, 2011, respectively. As of September 30, 2012, the unamortized discount is expected to be amortized into earnings over 6.4 years.
Material covenants were removed as part of the exchange offer and issuance of the Senior Secured Notes during December 2011.
NOTE C – DERIVATIVE ACTIVITIES
The Company is subject to price fluctuations for natural gas and crude oil. Prices received for natural gas and crude oil sold on the spot market are volatile due to factors beyond the Company’s control. Reductions in crude oil and natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, capital expenditures and quantities of reserves recoverable on an economic basis. Any reduction in reserves, including reductions due to lower prices, can affect the Company’s liquidity and ability to obtain capital for acquisition and development activities.
To mitigate a portion of its exposure to fluctuations in commodity prices, the Company enters into financial price risk management activities with respect to a portion of projected crude oil and natural gas production through financial price swaps, collars and put spreads (collectively, “derivatives”). Additionally, the Company uses basis protection swaps to reduce basis risk. Basis is the difference between the price of the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas due to the geographic price differentials between a given cash market location and the futures contract delivery locations. Settlement or expiration of the hedges is designed to coincide as closely as possible with the physical sale of the commodity being hedged—daily for oil and monthly for natural gas—to obtain reasonable assurance that a gain in the cash sale will offset the loss on the hedge and vice versa.

12


The Company utilizes counterparties that the Company believes are credit-worthy entities at the time the transactions are entered into. The Company closely monitors the credit ratings of these counterparties. Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. However, the recent events in the financial markets demonstrate there can be no assurance that a counterparty financial institution will be able to meet its obligations to the Company.
None of the Company’s derivative instruments contain credit-risk-related contingent features. Additionally, the Company has not incurred any credit-related losses associated with derivative activities and believes that its counterparties will continue to be able to meet their obligations under these transactions.
As a result of hedging transactions entered into in the first nine months of 2012, the Company recorded a net derivative liability. This net derivative liability is being accounted for at fair value with the changes in fair value recorded to the consolidated statement of operations.
The following is a summary of the asset and liability fair values of our derivative contracts:
 
 
Asset Fair Value
 
Liability Fair Value
 
Net Derivative Fair Value
  
Balance Sheet Location
 
September 30, 2012
 
December 31, 2011
 
September 30, 2012
 
December 31, 2011
 
September 30, 2012
 
December 31, 2011
 
 
 
(in thousands)
 
(in thousands)
 
(in thousands)
Derivatives not designated as Hedging Instruments under ASC 815
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas
Current derivative liability
 
$
2,093

 
$

 
$
(3,369
)
 
$

 
$
(1,276
)
 
$

Natural gas basis
Current derivative liability
 

 

 
(114
)
 

 
(114
)
 

Crude oil
Current derivative asset
 
1,236

 

 
(318
)
 

 
918

 

Natural gas
Other liabilities – non-current
 
962

 

 
(1,373
)
 

 
(411
)
 

Natural gas basis
Other liabilities – non-current
 

 

 
(16
)
 

 
(16
)
 

Crude oil
Derivative instruments – non-current asset
 
1,782

 

 
(954
)
 

 
828

 

 
 
 
$
6,073

 
$

 
$
(6,144
)
 
$

 
$
(71
)
 
$


13


The following table summarizes the outstanding natural gas and crude oil derivative contracts the Company had in place as of September 30, 2012:
Effective Date
 
Maturity Date
 
Notional
Amount
Per
Month
 
Remaining
Notional
Amount as
of September 30, 2012
 
Additional
Put
Options
 
Floor
 
Ceiling
 
Designation under
ASC 815
Natural Gas (MMBtu):












 

10/1/2012

12/31/2012

413,659

1,240,978



$2.60

$2.60

Not designated
10/1/2012

12/31/2012

95,541

286,622



$2.50

$3.20

Not designated
1/1/2013

12/31/2013

353,559

4,242,710

$2.85

$3.50

$4.00

Not designated
1/1/2013

12/31/2013

82,240

986,876

$3.00

$3.68

$3.68

Not designated
Crude Oil (Bbls):














10/1/2012

12/31/2012

4,030

12,089



$106.40

$106.40

Not designated
10/1/2012

12/31/2012

5,060

15,180



$96.50

$96.50

Not designated
10/1/2012

12/31/2013

2,950

8,850

$90.00

$100.00

$100.00

Not designated
1/1/2013

12/31/2013

3,548

42,579

$65.50

$106.40



Not designated
1/1/2013

12/31/2013

3,194

38,325

$70.00

$90.00



Not designated
1/1/2013

12/31/2013

2,221

26,654



$100.00



Not designated
1/1/2013

12/31/2013

9,151

109,814





$110.00

Not designated
1/1/2014

12/31/2014

2,961

35,528

$80.00

$100.00

$114.10

Not designated
1/1/2014

12/31/2014

1,658

19,893

$75.00

$95.00



Not designated
1/1/2014

12/31/2014

3,042

36,500

$70.00

$90.00



Not designated
All of the above natural gas contracts are settled against NYMEX, and all oil contracts are settled against NYMEX Light Sweet Crude. The NYMEX and NYMEX Light Sweet Crude have historically had a high degree of correlation with the actual prices received by the Company. In connection with our natural gas swaps, we also entered into a Basis Swap in which we locked in a natural gas price at the Houston Ship Channel at a $0.08/MMbtu discount to NYMEX. The combination of these trades effectively locks in a sales price to GMXR of $2.52 for 1.24 BCF during the last 3 months of 2012, and $3.42 for 4.24 BCF during 2013.
Effects of derivative instruments on the Consolidated Statement of Operations
For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income ("OCI") and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.
In December 2011, the Company settled its entire hedge portfolio. Under ASC 815-30-40, the Company is required to recognize the balance of the cumulative gain, recorded in accumulated other comprehensive income in the previous periods, over the life of the remaining contractual life of the original hedged transaction. For the three and nine months ended September 30, 2012, the Company recognized $4.0 million and $13.5 million, respectively, of the cumulative gain in oil and gas sales on the consolidated statement of operations. As of September 30, 2012, the balance of the Company's cumulative gain, net of taxes, recorded in accumulated other comprehensive income was $5.1 million, of which $2.1 million will be recognized into earnings through December 31, 2012, with the remainder recognized in 2013.

14


There were no oil or gas derivatives classified as hedges for the three and nine months ended September 30, 2012. A summary of the effect of the natural gas derivatives qualifying for hedges for the three and nine months ended September 30, 2011 is as follows:
 
 
 
Natural Gas Derivatives
Qualifying as Hedges
 
Location of
Amounts
 
Three Months Ended September 30, 2011
 
 
 
(in thousands)
Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion)
OCI
 
11,689

Amount of Gain Reclassified from Accumulated OCI into Income (Effective Portion)
Oil and Gas
Sales
 
4,671

Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Oil and Gas
Sales
 
(2,072
)
 
 
 
Natural Gas Derivatives
Qualifying as Hedges
 
Location of
Amounts
 
Nine Months Ended September 30, 2011
 
 
 
(in thousands)
Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion)
OCI
 
11,694

Amount of Gain Reclassified from Accumulated OCI into Income (Effective Portion)
Oil and Gas
Sales
 
13,107

Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Oil and Gas
Sales
 
(1,349
)

15


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
 
 
 
Three Months Ended
September 30,
 
 
 
2012
 
2011
 
 
 
(in thousands)
Realized
 
 
 
 
 
Natural gas
Oil and gas sales
 
$
(433
)
 
$

Crude oil
Oil and gas sales
 
324

 

 
 
 
$
(109
)
 
$

Unrealized
 
 
 
 
 
Natural gas
Unrealized gain or (loss)on derivatives
 
(223
)
 
(1,511
)
Crude oil
Unrealized gain or (loss)on derivatives
 
(1,101
)
 
173

 
 
 
$
(1,324
)
 
$
(1,338
)
 
Location of Gain (Loss) Recognized in
Income on Derivative
 
Amount of Gain (Loss) Recognized in
Income on Derivative
 
 
 
Nine Months Ended
September 30,
 
 
 
2012
 
2011
 
 
 
(in thousands)
Realized
 
 
 
 
 
Natural gas
Oil and gas sales
 
$
75

 
$

Crude oil
Oil and gas sales
 
568

 
(44
)
 
 
 
$
643

 
$
(44
)
Unrealized
 
 
 
 
 
Natural gas
Unrealized gain or (loss)on derivatives
 
(1,817
)
 
3,599

Crude oil
Unrealized gain or (loss)on derivatives
 
1,272

 
55

 
 
 
$
(545
)
 
$
3,654


16


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 September 30, 2012 and December 31, 2011:
 
As of September 30, 2012
 
As of December 31, 2011
 
Quoted
Prices  in
Active
Markets
(Level  1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Quoted
Prices  in
Active
Markets
(Level  1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
(in thousands)
Financial assets:
 
 
 
 
 
 
 
 
 
 
 
Natural gas derivative instruments
$

 
$
(1,817
)
 
$

 
$

 
$

 
$

Crude oil derivative instruments
$

 
$
1,746

 
$

 
$

 
$

 
$

NOTE D – STOCK COMPENSATION PLANS
We recognized $1.0 million and $0.9 million of stock compensation expense for the three months ended September 30, 2012 and 2011, respectively, and $3.5 million and $3.3 million for the nine months ended September 30, 2012 and 2011, respectively. These non-cash expenses are reflected as a component of the Company’s general and administrative expense. To the extent recognized compensation costs relates to employees directly involved in exploration and development activities, such amounts are capitalized to oil and natural gas properties. Stock-based compensation capitalized as part of oil and natural gas properties was $0.1 million and $0.1 million for the three months ended September 30, 2012 and 2011, respectively, and $0.3 million and $0.4 million for the nine months ended September 30, 2012 and 2011, respectively.
Restricted Stock
A summary of the status of our unvested shares of restricted stock and the changes for the year ended December 31, 2011 and the nine months ended September 30, 2012 is presented below:
 
Number of
unvested
restricted shares
 
Weighted
average  grant-
date fair value
per share
Unvested shares as of December 31, 2010
691,996

 
$
13.47

Granted
807,848

 
$
4.79

Vested
(245,924
)
 
$
16.46

Forfeited
(5,521
)
 
$
19.42

Unvested shares as of December 31, 2011
1,248,399

 
$
7.24

Vested
(612,984
)
 
$
7.23

Forfeited
(56,257
)
 
$
7.74

Unvested shares as of September 30, 2012
579,158

 
$
7.21

In March 2012, the vesting period of the restricted shares issued to the executives and members of the Board of Directors on August 2, 2011 were accelerated to an earlier date. There were no incremental compensation costs calculated as a result of the modification. Unamortized compensation costs were accelerated to earlier future periods consistent with the new vesting schedule of the restricted shares.
As of September 30, 2012, there was $3.2 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 0.9 years.

NOTE E – CAPITAL STOCK
Share Lending Arrangement
In February 2008, in connection with the offer and sale of the 5.00% Convertible Notes, we entered into a share lending agreement (the “Share Lending Agreement”). Under this agreement, we loaned to the share borrower up to the maximum

17


number of shares of our common stock underlying the 5.00% Convertible Notes. As of September 30, 2012 there were 2,364,375 shares of our outstanding common stock subject to loans to the share borrower under the Share Lending Agreement.
Issuance of Common Stock
During the nine months ended September 30, 2012, the Company converted $20.8 million aggregate principal amount of its 5.00% Convertible Notes due 2013 to 11,271,510 shares of common stock. See Note B, Long-Term Debt.
During the nine months ended September 30, 2012, the Company issued 7,176,384 shares of common stock in connection with the note exchange discussed in Note B, Long-term Debt.

NOTE F – INCOME TAXES
We recorded a tax provision of $1.4 million and a tax benefit of $2.4 million for the three months ended September 30, 2012 and 2011, respectively. For the nine months ended September 30, 2012 and 2011, we recorded a tax provision of $4.7 million and $0.5 million, respectively. The tax provision and benefit recorded for each period is due to changes in the valuation allowance on deferred tax assets.  The valuation allowance was adjusted due to increases or decreases in offsetting deferred tax liabilities, primarily as a result of unrealized gains or losses on derivative instruments that qualify for hedge accounting. In determining the carrying value of a deferred tax asset, accounting standards provide for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. As the Company has incurred net operating losses in prior years, relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are insufficient to overcome a history of such losses. In 2008, the Company reduced the carrying value of its net deferred tax asset to zero and maintained that position as of September 30, 2012 and December 31, 2011.  The valuation allowance has no impact on our net operating loss (“NOL”) position for tax purposes, and if the Company generates taxable income in future periods, the Company will be able to use its NOLs to offset taxes due at that time. The Company will continue to assess the valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.

NOTE G – COMMITMENTS AND CONTINGENCIES
Litigation
A putative class action lawsuit was filed by the Northumberland County Retirement System and Oklahoma Law Enforcement Retirement System (collectively, the “Northumberland Plaintiffs”) in the District Court in Oklahoma County, Oklahoma, purportedly on March 10, 2011, against the Company and certain of its officers along with certain underwriters of the Company's July 2008, May 2009 and October 2009 public offerings. Discovery requests and summons were filed and issued in late April 2011. The complaint alleges that the registration statement and the prospectuses for the offerings contained material misstatements and omissions and seeks damages under Sections 11, 12 and 15 of the Securities Act of 1933 of an unspecified equitable relief. Defendants removed the case to federal court on May 12, 2011 and filed motions to dismiss on June 20, 2011. Plaintiffs filed a motion to remand the case to state court on June 10, 2011, and Defendants filed an opposition to that motion. By order dated November 16, 2011, the court denied Plaintiffs' motion to remand. The Court stayed briefing and decision on the motions to dismiss. On February 3, 2012, Plaintiffs moved to be appointed lead plaintiff under the Private Securities Litigation Reform Act. By order dated July 3, 2012, the Court appointed the Northumberland Plaintiffs lead plaintiff. On August 17, 2012, Plaintiffs filed an amended complaint, which is similar to the original complaint except that it drops all claims relating to the 2008 offering because the financial statements incorporated into the July 2008 offering materials were not restated. On October 3, 2012, Defendants filed a motion to dismiss the amended complaint. Plaintiffs' opposition to the motions to dismiss is due November 15, and Defendants' reply is due November 30, 2012. We are currently unable to assess the probability of loss or estimate a range of potential loss, if any, associated with the securities class action case, which is at an early stage.
On August 5, 2011, an individual filed a shareholders' derivative action in the United States District Court for the Western District of Oklahoma, for the Company's benefit, as nominal defendant, against the Company's Chief Executive Officer, President, Chief Financial Officer, and certain members of the Company's board of directors. The complaint alleges breaches of fiduciary duty, waste of corporate assets, and unjust enrichment on the part of each of the named defendants and is premised on substantially the same facts alleged in the above-described securities lawsuit. The complaint seeks unspecified amounts of compensatory damages, implementation of certain corporate governance changes, and disgorgement of compensation and trading profits from the individual defendants, as well as interest and costs, including legal fees from the defendants. The Company is a nominal defendant, and the complaint does not seek any damages against the Company; however, the Company may have indemnification obligations to one or more of the defendants under the Company's organizational documents. On October 17, 2011, the individual defendants and the Company as nominal defendant filed motions to dismiss the complaint for failure to make demand, or in the alternative, to stay the derivative action pending the outcome of the securities lawsuit. The

18


case is currently stayed pending the outcome of the motions to dismiss with respect to the securities lawsuit described above. On March 23, 2012, an additional plaintiff filed a similar derivative action in the United States District Court for the Western District of Oklahoma. The parties agreed to consolidate this case with the existing federal court derivative action. The federal court derivative actions have been consolidated, and the cases are stayed pending the outcome of the motions to dismiss the securities lawsuit described above. We are currently unable to assess the probability of loss or estimate a range of potential loss, if any, associated with this case.
On February 7 and 9, 2012, two individuals filed separate shareholder derivative actions in the District Court of Oklahoma County, in the State of Oklahoma, for the Company's benefit, as nominal defendant, against the Company's Chief Executive Officer, President, Chief Financial Officer, and each member of the Company's board of directors. The petitions assert claims and seek relief similar to those asserted and sought in the federal court derivative action described above. Plaintiffs filed a motion to consolidate the two state court derivative actions, and the court consolidated the two actions. On April 9, 2012, defendants filed a motion to dismiss, a motion to stay, and a motion for protection from discovery. By stipulation dated May 29, 2012, the parties agreed to stay these cases pending the outcome of the motions to dismiss the securities lawsuit described above and to stay discovery. We are currently unable to assess the probability of loss or estimate a range of potential loss, if any, associated with this case.
The Company is party to various legal actions arising in the normal course of business. Matters that are probable to have an unfavorable outcome to the Company and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, the Company's estimates of the outcomes of such matters, and its experience in contesting, litigating, and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to the Company's financial position or results of operations after consideration of recorded accruals.
Insurance Matters
The Company maintains property damage, business interruption and other insurance coverage, the scope and amounts of which we believe are customary and prudent for the nature and extent of our operations. The Company also believes its deductibles are consistent with customary and prudent industry practices and does not expect that the payment of any deductibles would have a material adverse effect on the Company's financial condition or results of operations. While we believe the Company maintains adequate insurance coverage, insurance may not fully cover every type of damage, interruption or other loss that might occur.  If we were to incur a significant loss for which we were not fully insured, it could have a material impact on our financial position, results of operations and cash flows.  In addition, there may be a timing difference between amounts we are required to pay in connection with a loss and amounts we receive from insurance as reimbursement. Any event that materially interrupts the revenues generated by our consolidated operations, or other losses that require us to make material expenditures not covered by insurance, could adversely affect our cash flows and financial condition and, accordingly, adversely affect the market price of our securities.

19


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

Condensed Consolidating Balance Sheets
 
September 30, 2012
 
Parent
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
 
 
 
 
 
(In thousands)
 
 
 
 
ASSETS

 

 

 

 

CURRENT ASSETS

 

 

 

 

Cash and cash equivalents
$
14,983

 
$
40

 
$
512

 
$

 
$
15,535

Restricted cash
2,325

 

 

 

 
2,325

Short term investments

 

 

 

 

Accounts receivable – interest owners
4,813

 

 

 

 
4,813

Accounts receivable – oil and natural gas revenues, net
7,738

 
151

 

 
(3,260
)
 
4,629

Accounts receivable - intercompany
15,320

 
13,258

 
1,089

 
(29,667
)
 

Derivative instruments
918

 

 

 

 
918

Inventories
326

 

 

 

 
326

Prepaid expenses and deposits
1,058

 

 

 

 
1,058

Assets held for sale
410

 

 

 

 
410

Total current assets
47,891

 
13,449

 
1,601

 
(32,927
)
 
30,014

OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD

 

 

 


 

Properties being amortized
1,135,898

 
713

 
71

 

 
1,136,682

Properties not subject to amortization
158,574

 

 

 

 
158,574

Less accumulated depreciation, depletion, and impairment
(1,053,445
)
 

 

 

 
(1,053,445
)

241,027

 
713

 
71

 

 
241,811

PROPERTY AND EQUIPMENT, AT COST, NET
13,867

 
4,737

 
43,232

 

 
61,836

DERIVATIVE INSTRUMENTS
828

 

 

 

 
828

OTHER ASSETS
8,659

 

 

 

 
8,659

INVESTMENT IN SUBSIDIARIES
33,922

 

 

 
(33,922
)
 

TOTAL ASSETS
$
346,194

 
$
18,899

 
$
44,904

 
$
(66,849
)
 
$
343,148

LIABILITIES AND EQUITY

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

Accounts payable
10,266

 

 
7

 

 
10,273

Accounts payable - intercompany
13,539

 
16,018

 
110

 
(29,667
)
 

Accrued expenses
21,057

 
3,450

 
267

 
(3,260
)
 
21,514

Accrued interest
13,872

 

 

 

 
13,872

Revenue distributions payable
4,245

 

 

 

 
4,245

Short-term derivative instrument
1,390

 

 

 

 
1,390

Current maturities of long-term debt
26,876

 

 

 

 
26,876

Total current liabilities
91,245

 
19,468

 
384

 
(32,927
)
 
78,170

LONG-TERM DEBT, LESS CURRENT MATURITIES
380,528

 

 

 

 
380,528

DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS
402

 

 

 

 
402

OTHER LIABILITIES
8,543

 

 

 

 
8,543

EQUITY


 


 


 


 


Total GMX equity
(134,524
)
 
(569
)
 
44,520

 
(43,951
)
 
(134,524
)
Noncontrolling interest

 

 

 
10,029

 
10,029

Total equity
(134,524
)
 
(569
)
 
44,520

 
(33,922
)
 
(124,495
)
TOTAL LIABILITIES AND EQUITY
$
346,194

 
$
18,899

 
$
44,904

 
$
(66,849
)
 
$
343,148

 
 
 
 
 
 
 
 
 
 

20



 
December 31, 2011
 
Parent
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
 
 
 
 
 
(In thousands)
 
 
 
 
ASSETS
 
 
 
 
 
 
 
 
 
CURRENT ASSETS
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
98,118

 
$
3,672

 
$
703

 
$

 
$
102,493

Restricted cash
4,325

 

 

 

 
4,325

Accounts receivable – interest owners
8,607

 

 

 

 
8,607

Accounts receivable – oil and natural gas revenues, net
12,564

 
295

 

 
(5,777
)
 
7,082

Accounts receivable - intercompany
15,205

 
13,033

 
790

 
(29,028
)
 

Derivative instruments

 

 

 

 

Inventories
326

 

 

 

 
326

Prepaid expenses and deposits
2,574

 
2

 
79

 

 
2,655

Assets held for sale
1,999

 
46

 

 

 
2,045

Total current assets
143,718

 
17,048

 
1,572

 
(34,805
)
 
127,533

OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD

 

 

 


 

Properties being amortized
1,061,961

 
713

 
127

 

 
1,062,801

Properties not subject to amortization
147,224

 

 

 

 
147,224

Less accumulated depreciation, depletion, and impairment
(871,346
)
 

 

 

 
(871,346
)

337,839

 
713

 
127

 

 
338,679

PROPERTY AND EQUIPMENT, AT COST, NET
15,531

 
5,216

 
45,111

 

 
65,858

DERIVATIVE INSTRUMENTS

 

 

 

 

OTHER ASSETS
10,131

 

 

 

 
10,131

INVESTMENT IN SUBSIDIARIES
35,980

 

 

 
(35,980
)
 

TOTAL ASSETS
$
543,199

 
$
22,977

 
$
46,810

 
$
(70,785
)
 
$
542,201

LIABILITIES AND EQUITY

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

Accounts payable
13,527

 

 
23

 

 
13,550

Accounts payable - intercompany
13,126

 
15,684

 
218

 
(29,028
)
 

Accrued expenses
17,263

 
6,056

 
293

 
(5,777
)
 
17,835

Accrued interest
3,256

 

 

 

 
3,256

Revenue distributions payable
5,980

 

 

 

 
5,980

Current maturities of long-term debt
26

 

 

 

 
26

Total current liabilities
53,178

 
21,740

 
534

 
(34,805
)
 
40,647

LONG-TERM DEBT, LESS CURRENT MATURITIES
426,805

 

 

 

 
426,805

DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS

 

 

 

 

OTHER LIABILITIES
7,476

 

 

 

 
7,476

EQUITY


 


 


 


 


Total GMX equity
55,740

 
1,237

 
46,276

 
(47,513
)
 
55,740

Noncontrolling interest

 

 

 
11,533

 
11,533

Total equity
55,740

 
1,237

 
46,276

 
(35,980
)
 
67,273

TOTAL LIABILITIES AND EQUITY
$
543,199

 
$
22,977

 
$
46,810

 
$
(70,785
)
 
$
542,201

 
 
 
 
 
 
 
 
 
 

21



Condensed Consolidating Statements of Operations

 
 
 
 
 
 
 
 
 
 
 
Parent
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
 
 
 
 
 
(In thousands)
 
 
 
 
Three Months Ended September 30, 2012
 
 
 
 
 
 
 
 
 
TOTAL REVENUES
$
14,407

 
$
338

 
$
2,171

 
$
(2,325
)
 
$
14,591

COSTS AND EXPENSES

 

 

 

 

Lease operating
4,704

 
458

 
377

 
(2,280
)
 
3,259

Production taxes
499

 

 

 

 
499

Depreciation, depletion, and amortization
5,130

 
179

 
626

 

 
5,935

Impairment of oil and natural gas properties and assets held for sale
45,506

 

 

 

 
45,506

General and administrative
5,036

 
322

 
55

 
(45
)
 
5,368

Total expenses
60,875

 
959

 
1,058

 
(2,325
)
 
60,567

Income (loss) from operations
(46,468
)
 
(621
)
 
1,113

 

 
(45,976
)
NON-OPERATING INCOME (EXPENSE)

 

 

 

 

Interest expense
(10,065
)
 

 

 

 
(10,065
)
Gain (loss) on conversion/extinguishment of debt
1,502

 

 

 

 
1,502

Interest and other income
23

 

 

 

 
23

Unrealized gain on derivatives
(1,324
)
 

 

 

 
(1,324
)
Equity income (loss) of subsidiaries
(398
)
 

 

 
398

 

Total non-operating expense
(10,262
)
 

 

 
398

 
(9,864
)
Income (loss) before income taxes
(56,730
)
 
(621
)
 
1,113

 
398

 
(55,840
)
INCOME TAX PROVISION
(1,389
)
 

 

 

 
(1,389
)
NET INCOME (LOSS)
(58,119
)
 
(621
)
 
1,113

 
398

 
(57,229
)
Net income attributable to noncontrolling interest

 

 

 
890

 
890

NET (LOSS) INCOME APPLICABLE TO GMX RESOURCES
(58,119
)
 
(621
)
 
1,113

 
(492
)
 
(58,119
)
Preferred stock dividends
1,837

 

 

 

 
1,837

NET (LOSS) INCOME APPLICABLE TO COMMON SHAREHOLDERS
$
(59,956
)
 
$
(621
)
 
$
1,113

 
$
(492
)
 
$
(59,956
)
 
 
 
 
 
 
 
 
 
 


22



 
 
 
 
 
 
 
 
 
 
 
Parent
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
 
 
 
 
 
(In thousands)
 
 
 
 
Three Months Ended September 30, 2011
 
 
 
 
 
 
 
 
 
TOTAL REVENUES
$
27,838

 
$
1,063

 
$
2,859

 
$
(3,396
)
 
$
28,364

COSTS AND EXPENSES

 

 

 

 

Lease operating
4,511

 
1,198

 
662

 
(3,177
)
 
3,194

Production taxes
310

 

 

 

 
310

Depreciation, depletion, and amortization
13,183

 
180

 
626

 

 
13,989

Impairment of oil and natural gas properties and assets held for sale
60,941

 
1,054

 
555

 

 
62,550

General and administrative
7,290

 
444

 
94

 
(219
)
 
7,609

Total expenses
86,235

 
2,876

 
1,937

 
(3,396
)
 
87,652

Income (loss) from operations
(58,397
)
 
(1,813
)
 
922

 

 
(59,288
)
NON-OPERATING INCOME (EXPENSE)

 

 

 

 

Interest expense
(7,680
)
 

 

 

 
(7,680
)
Gain (loss) on conversion/extinguishment of debt

 

 

 

 

Interest and other income
9

 

 

 

 
9

Unrealized gain on derivatives
(1,338
)
 

 

 

 
(1,338
)
Equity income (loss) of subsidiaries
(2,072
)
 

 

 
2,072

 

Total non-operating expense
(11,081
)
 

 

 
2,072

 
(9,009
)
Income (loss) before income taxes
(69,478
)
 
(1,813
)
 
922

 
2,072

 
(68,297
)
INCOME TAX PROVISION
2,386

 

 

 

 
2,386

NET INCOME (LOSS)
(67,092
)
 
(1,813
)
 
922

 
2,072

 
(65,911
)
Net income attributable to noncontrolling interest

 

 

 
1,181

 
1,181

NET (LOSS) INCOME APPLICABLE TO GMX RESOURCES
(67,092
)
 
(1,813
)
 
922

 
891

 
(67,092
)
Preferred stock dividends
1,837

 

 

 

 
1,837

NET (LOSS) INCOME APPLICABLE TO COMMON SHAREHOLDERS
$
(68,929
)
 
$
(1,813
)
 
$
922

 
$
891

 
$
(68,929
)
 
 
 
 
 
 
 
 
 
 


23



 
 
 
 
 
 
 
 
 
 
 
Parent
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
 
 
 
 
 
(In thousands)
 
 
 
 
Nine Months Ended September 30, 2012
 
 
 
 
 
 
 
 
 
TOTAL REVENUES
$
47,641

 
$
1,057

 
$
6,499

 
$
(6,922
)
 
$
48,275

COSTS AND EXPENSES

 

 

 

 

Lease operating
13,679

 
1,323

 
1,015

 
(6,762
)
 
9,255

Production taxes
818

 

 

 

 
818

Depreciation, depletion, and amortization
17,958

 
537

 
1,879

 

 
20,374

Impairment of oil and natural gas properties and assets held for sale
166,321

 

 
(125
)
 

 
166,196

General and administrative
18,169

 
1,003

 
153

 
(160
)
 
19,165

Total expenses
216,945

 
2,863

 
2,922

 
(6,922
)
 
215,808

Income (loss) from operations
(169,304
)
 
(1,806
)
 
3,577

 

 
(167,533
)
NON-OPERATING INCOME (EXPENSE)

 

 

 

 

Interest expense
(30,889
)
 

 
(1
)
 

 
(30,890
)
Gain (loss) on conversion/extinguishment of debt
5,114

 

 

 

 
5,114

Interest and other income
131

 

 

 

 
131

Unrealized gain on derivatives
(545
)
 

 

 

 
(545
)
Equity income (loss) of subsidiaries
(991
)
 

 

 
991

 

Total non-operating expense
(27,180
)
 

 
(1
)
 
991

 
(26,190
)
Income (loss) before income taxes
(196,484
)
 
(1,806
)
 
3,576

 
991

 
(193,723
)
INCOME TAX PROVISION
(4,694
)
 

 

 

 
(4,694
)
NET INCOME (LOSS)
(201,178
)
 
(1,806
)
 
3,576

 
991

 
(198,417
)
Net income attributable to noncontrolling interest

 

 

 
2,761

 
2,761

NET (LOSS) INCOME APPLICABLE TO GMX RESOURCES
(201,178
)
 
(1,806
)
 
3,576

 
(1,770
)
 
(201,178
)
Preferred stock dividends
5,510

 

 

 

 
5,510

NET (LOSS) INCOME APPLICABLE TO COMMON SHAREHOLDERS
$
(206,688
)
 
$
(1,806
)
 
$
3,576

 
$
(1,770
)
 
$
(206,688
)


 

 

 

 


24



 
 
 
 
 
 
 
 
 
 
 
Parent
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
 
 
 
 
 
(In thousands)
 
 
 
 
Nine Months Ended September 30, 2011
 
 
 
 
 
 
 
 
 
TOTAL REVENUES
$
89,106

 
$
2,500

 
$
8,943

 
$
(9,920
)
 
$
90,629

COSTS AND EXPENSES

 

 

 

 

Lease operating
13,686

 
3,223

 
1,395

 
(9,339
)
 
8,965

Production taxes
859

 

 

 

 
859

Depreciation, depletion, and amortization
37,661

 
554

 
1,868

 

 
40,083

Impairment of oil and natural gas properties and assets held for sale
120,680

 
6,404

 
647

 

 
127,731

General and administrative
21,162

 
1,448

 
255

 
(581
)
 
22,284

Total expenses
194,048

 
11,629

 
4,165

 
(9,920
)
 
199,922

Income (loss) from operations
(104,942
)
 
(9,129
)
 
4,778

 

 
(109,293
)
NON-OPERATING INCOME (EXPENSE)

 

 

 

 

Interest expense
(23,533
)
 

 
(1
)
 

 
(23,534
)
Gain (loss) on conversion/extinguishment of debt
(176
)
 

 

 

 
(176
)
Interest and other income
215

 

 
76

 

 
291

Unrealized gain on derivatives
3,654

 

 

 

 
3,654

Equity income (loss) of subsidiaries
(8,615
)
 


 


 
8,615

 

Total non-operating expense
(28,455
)
 

 
75

 
8,615

 
(19,765
)
Income (loss) before income taxes
(133,397
)
 
(9,129
)
 
4,853

 
8,615

 
(129,058
)
INCOME TAX PROVISION
(481
)
 

 

 

 
(481
)
NET INCOME (LOSS)
(133,878
)
 
(9,129
)
 
4,853

 
8,615

 
(129,539
)
Net income attributable to noncontrolling interest

 

 

 
4,339

 
4,339

NET (LOSS) INCOME APPLICABLE TO GMX RESOURCES
(133,878
)
 
(9,129
)
 
4,853

 
4,276

 
(133,878
)
Preferred stock dividends
4,884

 

 

 

 
4,884

NET (LOSS) INCOME APPLICABLE TO COMMON SHAREHOLDERS
$
(138,762
)
 
$
(9,129
)
 
$
4,853

 
$
4,276

 
$
(138,762
)


 

 

 

 


25



Condensed Consolidating Statements of Cash Flows
 
 
 
 
 
 
 
 
 
 
 
Parent
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
 
 
 
 
 
(In thousands)
 
 
 
 
Nine Months Ended September 30, 2012
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
$
(6,950
)
 
$
(3,625
)
 
$
5,146

 
$

 
$
(5,429
)
Net cash provided by (used in) investing activities
(72,262
)
 
(7
)
 
(6
)
 

 
(72,275
)
Net cash provided by (used in) financing activities
(3,923
)
 

 
(5,331
)
 

 
(9,254
)
Net decrease in cash
(83,135
)
 
(3,632
)
 
(191
)
 

 
(86,958
)
Cash and cash equivalents at beginning of period
98,118

 
3,672

 
703

 

 
102,493

Cash and cash equivalents at end of period
$
14,983

 
$
40

 
$
512

 
$

 
$
15,535

 

 

 

 

 

Nine Months Ended September 30, 2011
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
$
40,692

 
$
(377
)
 
$
7,767

 
$

 
$
48,082

Net cash provided by (used in) investing activities
(230,832
)
 
(113
)
 
5,004

 

 
(225,941
)
Net cash provided by (used in) financing activities
190,932

 

 
(12,202
)
 

 
178,730

Net decrease in cash
792

 
(490
)
 
569

 

 
871

Cash and cash equivalents at beginning of period
1,468

 
564

 
325

 

 
2,357

Cash and cash equivalents at end of period
$
2,260

 
$
74

 
$
894

 
$

 
$
3,228

 

 

 

 

 


NOTE I – SUBSEQUENT EVENTS
Sale of assets:
On October 24, 2012, the Company sold specified operated and non-operated oil and gas properties in the Cotton Valley Sands and shallow rights located in East Texas and Louisiana ("Cotton Valley Assets") for $66.7 million, net of selling costs and adjustments to reflect revenues and expenses related to the Cotton Valley Assets from September 1, 2012, the effective date of the sale, through September 30, 2012.
Reverse Stock Split
On October 10, 2012, the Company announced that it will hold a special meeting of the shareholders on November 29, 2012 to seek approval on granting the Board of Directors the discretionary authority to effect a reverse stock split. Shareholders of record as of the close of business on October 22, 2012 will be eligible to vote on the reverse stock split.
December Interest Payment
On October 17, 2012, the Company announced that it has selected the PIK election to pay the December 1, 2012 interest payment due on the Senior Secured Notes. The PIK election will increase the outstanding principal balance of the Senior Secured Notes by $5.8 million.
Commitment for the Purchase of $30 million of New Secured Notes and Common Equity
On November 7, 2012, the Company entered into separate commitment agreements (each a “Commitment Agreement” and collectively the “Commitment Agreements”) with several holders (the “Committed Holders”) of the Company's Senior Secured Notes (the “Existing Notes”), issued pursuant to the Indenture dated as of December 19, 2011 among the Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee and Collateral Agent (the “Senior Secured Notes Indenture”). Subject to, and in accordance with, the terms and conditions contained in these Commitment Agreements, each of the Committed Holders have agreed, among other things, to grant the Company the option to cause the Committed Holders to purchase from the Company in a private placement (i) an aggregate of $30.0 million principal amount of additional Senior Secured Notes (to be designated as a new series, the “Additional Notes”) and (ii) an aggregate of 5,942,034 newly-issued shares of common stock at a price equal to $0.48 per share. The Company understands that Committed Holders hold in the aggregate approximately 72% of the outstanding principal amount of the Existing Notes.
As consideration for the Committed Holders' obligations pursuant to the Commitment Agreements, the Company has agreed to pay to each Committed Holder a cash fee equal to 3.0% of the funded principal amount of the New Notes purchased by such Committed Holder and, upon closing of the Private Placement, to issue to each Committed Holder, for a purchase price per share of $0.01, 334.574 shares of Common Stock for each $1,000 principal amount of New Notes purchased by such Committed Holder.

26


The closing of the transactions is subject to the completion of definitive documents, the consents of holders of at least a majority of Existing Notes to certain proposed amendments to the Senior Secured Notes Indenture, obtaining all necessary consents and approvals from requisite governmental authorities and third parties, as well as other customary closing conditions. 

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ITEM 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following information should be read in conjunction with our unaudited consolidated financial statements and the condensed notes thereto included in this quarterly report on Form 10-Q. The following information and such unaudited consolidated financial statements should also be read in conjunction with the financial statements and related notes thereto, together with our discussion and analysis of our financial position and results of operations, included in our annual report on Form 10-K for the year ended December 31, 2011 (the “2011 Form 10-K”). Unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean the business and operations of GMX Resources Inc. and its consolidated subsidiaries.
In addition, various statements contained in or incorporated by reference into this document that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements are subject to numerous assumptions and risks, including risks described in our 2011 Form 10-K and in this document. Please read “Forward-Looking Statements” below.
General
We are an independent oil and gas company currently focused on development acreage in two oil shale resource plays in the Williston Basin (North Dakota/Montana), targeting the Bakken and Sanish-Three Forks Formations, and the DJ Basin (Wyoming), targeting the Niobrara Formation. Our natural gas resources are located in the East Texas Basin, in the Haynesville/Bossier ("H/B") gas shale and the Cotton Valley Sand Formation, where substantially all of our acreage is contiguous and held by production. We believe these oil and natural gas resource plays provide a substantial inventory of operated, high probability, repeatable, organic growth opportunities. The Bakken properties cover approximately 35,000 net acres and the Niobrara properties cover more than 40,000 net acres. The Company believes that having choices for operating in multiple basins and for focusing on oil or natural gas resources provides us with flexibility to allocate capital to achieve the highest risk-adjusted rate of return on our portfolio. We also intend to convert our unproved reserves in these areas into proved reserves. We may selectively acquire additional acreage in these areas in the normal course of business.
Our current focus is on increasing oil production and focusing our operations in McKenzie and Billings Counties, North Dakota, where we are currently operating ten wells, including one well waiting on completion, and one rig operating. We also have non-operating interests in five additional wells in this area.
In Wyoming, our Niobrara development has begun with two seismic shoots encompassing 135 and 204 square miles. Our first shoot and part of our second shoot are complete and we are evaluating the results. The remainder of our second shoot is expected to be completed in the 4th quarter.
We plan to commit almost all of our total capital expenditures in the remainder of 2012 to our oil resources development. We expect that increasing the oil percentage of our production will have positive economic benefits created by the current price gap that exists between oil and natural gas. We plan to continue to use hedging to mitigate commodity price risks for our oil and gas production.
Recent Events
The Company's balance on its 5.00% Convertible Notes due 2013 at year-end 2011 was $72.8 million. In addition to the exchange for Senior Secured Second-Priority Notes discussed below, the Company has completed a total of six separately negotiated debt-for-equity exchange transactions with holders of the 5.00% Convertible Notes during 2012. The debt for equity transactions have resulted in the issuance of 11,271,510 shares of common stock and has reduced the principal amount of the 5.00% Convertible Notes by $20.8 million million. As of September 30, 2012, the outstanding principal balance of the 5.00% Convertible Notes was $27.1 million. See "Capital Resources and Liquidity" in regards to the Company's agreements with certain holders of the Company's existing Senior Secured Notes to provide financing commitments for use to retire the remaining $27.1 million principal amount of the 5.00% Convertible Notes outstanding as of September 30, 2012, by issuing $30.0 million principal amount of new Senior Secured Notes.
On September 19, 2012, the Company issued (i) $24,918,000 aggregate principal amount of Senior Secured Second-Priority Notes due 2018 ("2018 Notes") and 7,136,384 shares of common stock in exchange for $24,918,000 aggregate principal amount of our 5.00% Convertible Notes due 2013 and (ii) $26,540,000 aggregate principal amount of 2018 Notes in exchange for $37,954,000 aggregate principal amount of our 4.50% Convertible Notes due 2015.

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On October 10, 2012, the Company announced that it will hold a special meeting of the shareholders on November 29, 2012 for shareholders of record as of the close of business on October 22, 2012 to seek approval on the granting to the Board of Directors the discretionary authority to effect a reverse stock split in a range of not less than 1-for-5 shares and not more than 1-for-13 shares of the Company's issued and outstanding common stock. The reverse stock split proposal will not include any change to the number of authorized shares of our common stock.
On October 24, 2012, the Company sold specified operated and non-operated oil and gas properties in the Cotton Valley Sands and shallow rights located in East Texas and Louisiana for approximately $66.7 million, net of revenues and expenses for the month of September 2012 and selling costs.


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The table below summarizes information concerning our operating activities in the three and nine months ended September 30, 2012 compared to the three and nine months ended September 30, 2011.
Summary Operating Data
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012 (1)
 
2011
 
2012 (1)
 
2011
Production:
 
 
 
 
 
 
 
Oil (MBbls)
53

 
19

 
148

 
65

Natural gas (MMcf)
2,488

 
5,568

 
7,539

 
16,936

Natural gas liquids (MBbls)
19

 
77

 
214

 
230

Gas equivalent production (MMcfe)
2,919

 
6,142

 
9,712

 
18,706

Natural gas VPP volumes (MMcfe)
921

 

 
3,109

 

Gas equivalent production including VPP volumes (MMcfe)
3,840

 
6,142

 
12,821

 
18,706

Average daily production excluding VPP volumes (MMcfe)
31.7

 
66.8

 
35.4

 
68.5

Average daily production including VPP volumes (MMcfe)
41.7

 
66.8

 
46.8

 
68.5

Average Sales Price:
 
 
 
 
 
 
 
Oil (per Bbl)
 
 
 
 
 
 
 
Wellhead price
$
84.70

 
$
88.03

 
$
87.33

 
$
93.98

Effect of hedges, excluding gain or loss from ineffectiveness of derivatives
6.08

 

 
3.83

 
(0.67
)
Total
$
90.78

 
$
88.03

 
$
91.16

 
$
93.31

Natural gas liquids (per Bbl)
 
 
 
 
 
 
 
Sales price
$
36.27

 
$
43.10

 
$
34.55

 
$
39.82

Effect of hedges, excluding gain or loss from ineffectiveness of derivatives

 

 

 

Total
$
36.27

 
$
43.10

 
$
34.55

 
$
39.82

Natural gas (per Mcf)
 
 
 
 
 
 
 
Wellhead price
$
2.23

 
$
3.73

 
$
1.83

 
$
3.76

Effect of hedges, excluding gain or loss from ineffectiveness of derivatives
1.42

 
0.84

 
1.80

 
0.77

Total
$
3.65

 
$
4.57

 
$
3.63

 
$
4.53

Average sales price, excluding gain or loss from ineffectiveness of derivatives (per Mcfe)
$
5.00

 
$
4.95

 
$
4.97

 
$
4.92

Operating and Overhead Costs (per Mcfe):
 
 
 
 
 
 
 
Lease operating expenses including VPP volumes
$
0.85

 
$
0.52

 
$
0.72

 
$
0.48

Effect of excluding VPP volumes on lease operating expenses
0.27

 

 
0.23

 

Lease operating expense excluding VPP volumes
$
1.12

 
$
0.52

 
$
0.95

 
$
0.48

 
 
 
 
 
 
 
 
Production and severance taxes including VPP volumes
$
0.13

 
$
0.05

 
$
0.06

 
$
0.05

Effect of excluding VPP volumes on production and severance taxes
0.04

 

 
0.02

 

Production and severance taxes excluding VPP volumes
$
0.17

 
$
0.05

 
$
0.08

 
$
0.05

 
 
 
 
 
 
 
 
General and administrative including VPP volumes
$
1.40

 
$
1.24

 
$
1.49

 
$
1.19

Effect of excluding VPP volumes on general and administrative
0.44

 

 
0.48

 

General and administrative excluding VPP volumes
$
1.84

 
$
1.24

 
$
1.97

 
$
1.19

 
 
 
 
 
 
 
 
Total cost including VPP volumes
$
2.38

 
$
1.81

 
$
2.27

 
$
1.72

Total cost excluding VPP Volumes
$
3.13

 
$
1.81

 
$
3.00

 
$
1.72

 
 
 
 
 
 
 
 
Other (per Mcfe):
 
 
 
 
 
 
 
Depreciation, depletion and amortization—oil and natural gas properties (excluding VPP volumes)
$
1.52

 
$
2.03

 
$
1.63

 
$
1.90

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

30


Results of Operations for the Three Months Ended September 30, 2012 Compared to the Three Months Ended September 30, 2011
Oil and Natural Gas Sales. Oil and natural gas sales during the three months ended September 30, 2012 decreased 49% to $14.6 million compared to $28.4 million in the third quarter of 2011. The decrease in oil and gas sales was primarily due to a 52% decrease in production on a Bcfe-basis of which 29% of the decrease was attributable to natural gas volumetric production payment ("VPP") volumes of 0.9 Bcfe that were sold in the form of a term overriding royalty interest in December 2011 and the remainder of the decrease was a result of the natural decline from the Company's H/B production due to the suspension of the Company's H/B horizontal drilling program in mid-2011. The average price per barrel of oil, per barrel of natural gas liquids ("NGLs") and price per thousand cubic feet (Mcf) of natural gas received (exclusive of ineffectiveness from derivatives) in the three months ended September 30, 2012 was $90.78, $36.27 and $3.65, respectively, compared to $88.03, $43.10 and $4.57, respectively, in the three months ended September 30, 2011. This represented a 3% increase in oil prices, a 16% decrease in the average realized price in NGLs, and a 20% decrease in the average realized price of natural gas. Our realized sales price for natural gas, including revenue from NGLs and excluding the effect of hedges of $1.42 and $0.84, for the three months ended September 30, 2012 and 2011, respectively, was approximately 89% and 89% of the average NYMEX closing contract price for the respective periods. In the third quarter of 2012 and 2011, the conversion of natural gas to NGLs produced an upgrade of approximately $0.27 per Mcf and $0.29 per Mcf, respectively, for every Mcf of natural gas sold.
Natural gas production for the three months ended September 30, 2012 decreased to 2.5 Bcf compared to 5.6 Bcf for the three months ended September 30, 2011, a decrease of 55%. Including the VPP volumes of 0.9 Bcf, natural gas production decreased by 2.2 Bcf, or 39%. The decrease in natural gas production resulted primarily from the natural decline in the Company's H/B wells as a result of the suspension of the Company's H/B horizontal drilling program in mid-2011. The Company's last H/B well was completed and brought on line in August 2011.
Oil production for the three months ended September 30, 2012 increased 185% to 53,305 Bbls, from 18,733 Bbls for the three months ended September 30, 2011, primarily as a result of the Company's new Bakken production. For the third quarter of 2012, the Company produced 37,558 Bbls in the Bakken and 15,747 Bbls in East Texas compared to the third quarter of 2011 when the Company only had East Texas oil production. Bakken and East Texas oil sales, excluding hedges, during the three months ended September 30, 2012 were $3.1 million and $1.5 million, respectively.
NGL production for the three months ended September 30, 2012 decreased to 18,583 Bbls compared to 76,997 Bbls for the three months ended September 30, 2011, a decrease of 76%. Due to the limitations in NGL infrastructure in the third quarter of 2012 and the resulting decrease in available processing capacity, the Company elected to sell a portion of our unprocessed gas in the Carthage Texas area for a total price that was greater than the combined estimated price of residue gas and the net processing upgrade. Since the NGLs can be left in or extracted from the gas stream, we will continue to make gas dispatch decisions based on maximizing the total sales value of the combined hydrocarbon stream.
For the three months ended September 30, 2012, as a result of hedging activities, excluding derivative ineffectiveness, we recognized an increase in oil and natural gas sales of $3.9 million compared to an increase in oil and natural gas sales of $4.7 million in the third quarter of 2011. In the third quarter of 2012, hedging, excluding ineffectiveness, increased the average natural gas sales price by $1.42 per Mcf compared to an increase in natural gas sales price of $0.84 per Mcf in the third quarter of 2011. The increase in the natural gas sales price for the three months ended September 30, 2012, was mainly due to the amortization of $4.0 million in realized non-cash gain on our cash flow hedges that we monetized in the fourth quarter 2011. The remaining realized gain of $5.1 million, net of taxes, in other comprehensive income will be amortized into earnings ratably through 2013. Our derivative contracts that have not been monetized on natural gas decreased our natural gas sales by $0.4 million and increased our natural gas sales by $4.7 million for the three months ended September 30, 2012 and 2011, respectively. Our derivative contracts on oil increased our oil sales by $0.3 million for the three months ended September 30, 2012. The effect of our derivative contracts on oil increased the average oil sales price by $6.08 per Bbl for the three months ended September 30, 2012. The effect of our derivative contracts on oil had no effect for the three months ended September 30, 2011.
Lease Operations. Lease operations expense increased $0.1 million, or 2%, for the three months ended September 30, 2012, to $3.3 million, compared to $3.2 million for the three months ended September 30, 2011. Lease operations expense on a per thousand cubic feet equivalent (Mcfe) basis, excluding VPP volumes increased $0.60, or 115%, to $1.12 for the three months ended September 30, 2012 compared to $0.52 for the three months ended September 30, 2011. The increase in lease operating expenses in total and on a per Mcfe basis is due to higher lease operating expenses related to the Company's Bakken oil production and the impact of the volumetric production payment of $0.27 per Mcfe. For the three months ended September 30, 2012, lease operations expense on a per Mcfe basis for East Texas and the Bakken was $0.94 and $3.20, respectively.

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Production and Severance Taxes. Production and severance taxes increased 61% to $0.5 million in the three months ended September 30, 2012 compared to $0.3 million in the three months ended September 30, 2011. The increase in production and severance taxes is primarily due to the increase in the Bakken production, which results in higher production taxes compared to no production in the Bakken for the same period in 2011.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $8.1 million, or 58%, to $5.9 million in the three months ended September 30, 2012 compared to $14.0 million for the three months ended September 30, 2011. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.52 per Mcfe in the three months ended September 30, 2012 compared to $2.03 per Mcfe in the three months ended September 30, 2011. This decrease in the rate per Mcfe is primarily due to the recent impairment charges recognized by the Company which has lowered the amount of oil and gas properties subject to amortization.
Impairment of oil and natural gas properties and assets held for sale. The Company recorded an impairment charge of $45.5 million in the third quarter of 2012, which was related to the impairment of oil and gas properties subject to the full cost ceiling test. The primary factors impacting the full cost method ceiling test are expenditures added to the full cost pool, reserve levels, value of cash flow hedges, and natural gas and oil prices, and their associated impact on the present value of estimated future net revenues. Any excess of the net book value is generally written off as an expense. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Natural gas represented approximately 85% of the Company’s total production for the three months ended September 30, 2012. During the third quarter of 2012, the 12-month average of the first day of the month natural gas price decreased 10% from $3.15 per MMbtu at June 30, 2012 to $2.82 per MMbtu at September 30, 2012, contributing to the impairment for the third quarter of 2012. Of the $45.5 million impairment of oil and gas properties, $33.5 million was related to the decrease in natural gas and oil prices and $12.0 million was related to continued infrastructure and operational constraints impacting proved producing reserves in the Bakken. The Company anticipates positive Bakken reserve revisions in the future.
    General and Administrative Expense. General and administrative expense for the three months ended September 30, 2012 was $5.4 million, compared to $7.6 million for the three months ended September 30, 2011, a decrease of $2.2 million, or 29%, as a result of cost cutting measures implemented by the Company in early 2012. General and administrative expenses include $1.0 million and $0.9 million of non-cash compensation expense as of the three months ended September 30, 2012 and 2011, respectively. Non-cash compensation represented 19% and 12% of total general and administrative expenses, for the three months ended September 30, 2012 and 2011, respectively. General and administrative expense has not historically varied in direct proportion to oil and natural gas production because certain types of general and administrative expenses are non-recurring or fixed in nature.
Interest. Interest expense for the three months ended September 30, 2012 was $10.1 million compared to $7.7 million for the same period in 2011, an increase of $2.4 million or 31%. The increase in interest expense was primarily due to the Company's decision in 2012 to elect the PIK option ("PIK Election") on its Senior Secured Notes due 2017 that allows for a 9% cash interest payment along with a 4% interest payment in the form of additional Senior Secured Notes resulting in an annual interest rate of 13%, as well as the increase in the amount of the outstanding debt between the periods as a result of the exchange offer completed in December 2011. As part of the exchange, certain parties purchased an additional $100 million of the Senior Secured Notes for a total issuance of $283.5 million of the new Senior Secured Notes due 2017. For the three months ended September 30, 2011, only the $2.0 million of 11.375% Senior Notes due 2019 were outstanding.
For the three months ended September 30, 2012 and 2011, interest expense includes non-cash interest expense of $1.0 million and $1.4 million, respectively, related to the accounting for convertible bonds, our share lending agreement and deferred premiums on derivative instruments. Cash interest expense for the three months ended September 30, 2012 and 2011 was $8.3 million and $7.8 million, respectively, of which $3.1 million and $2.5 million, respectively, was capitalized to properties not subject to amortization on the consolidated balance sheets. Interest associated with the PIK Election was $2.9 million for the three months ended September 30, 2012. The increase in cash and PIK Election interest expense was mainly due to the Company's completion of an exchange offer in December 2011 for all but $2 million of the 11.375% Senior Notes due 2019 which resulted in $288.6 million of new Senior Secured Notes due 2017 and an increase in debt of $90.6 million. The increase in interest expense was partially offset by the reduction in the 5.00% Convertible Notes during 2012.
Income Taxes. Income tax expense for the three months ended September 30, 2012 was $1.4 million as compared to a benefit of $2.4 million in the same period in 2011. The income tax expense/benefit recognized in the three months ended September 30, 2012 and 2011, respectively, was a result of a change in the valuation allowance on net deferred tax assets caused by a change in deferred tax liabilities primarily related to gains on derivative contracts designated as hedges where the mark-to-market change on the hedges, net of deferred taxes, is recorded to other comprehensive income.

32


Net income to non-controlling interest. Net income to non-controlling interest was $0.9 million for the three months ended September 30, 2012 compared to $1.2 million for the three months ended September 30, 2011. This decrease was due to lower natural gas production in East Texas.
Results of Operations for the Nine Months Ended September 30, 2012 Compared to the Nine Months Ended September 30, 2011
Oil and Natural Gas Sales. Oil and natural gas sales during the nine months ended September 30, 2012 decreased 47% to $48.3 million compared to $90.6 million in the nine months ended September 30, 2011. The decrease in oil and gas sales was primarily due to a 48% decrease in production on a Bcfe-basis of which 35% was attributable to natural gas VPP volumes of 3.1 Bcfe that were sold in the form of a term overriding royalty interest in December 2011 and the remainder was the result of the natural decline from the Company's H/B production due to the suspension of the Company's H/B horizontal drilling program in mid-2011. The average price per barrel of oil, per barrel of NGLs and per Mcf of natural gas received (exclusive of ineffectiveness from derivatives) in the nine months ended September 30, 2012 was $91.16, $34.55 and $3.63, respectively, compared to $93.31, $39.82 and $4.53, respectively, in the nine months ended September 30, 2011. This represented a 2% decrease in oil prices, a 13% decrease in the average realized price in NGLs, and a 20% decrease in the average realized price of natural gas. Our realized sales price for natural gas, including revenue from NGLs and excluding the effect of hedges of $1.80 and $0.77, for the nine months ended September 30, 2012 and 2011, respectively, was approximately 109% and 89% of the average NYMEX closing contract price for the respective periods. In the nine months ended September 30, 2012 and 2011, the conversion of natural gas to NGLs produced an upgrade of approximately $0.98 per Mcf and $0.33 per Mcf, respectively, for every Mcf of natural gas sold.
Natural gas production for the nine months ended September 30, 2012 decreased to 7.5 Bcf compared to 16.9 Bcf for the nine months ended September 30, 2011, a decrease of 55%. Including VPP volumes of 3.1 Bcf, natural gas production decreased by 6.3 Bcf, or 37%. The decrease in natural gas production resulted primarily from the natural decline in the Company's H/B wells as a result of the suspension of the Company's H/B horizontal drilling program in mid-2011. The Company's last H/B well was completed and brought on line in August 2011.
Oil production for the nine months ended September 30, 2012 increased by 130% to 148,416 Bbls, from 64,667 Bbls for the nine months ended September 30, 2011, primarily as a result of the Company's new Bakken production. For the first nine months of 2012, the Company produced 90,999 Bbls in the Bakken and 57,417 Bbls in East Texas compared to only having East Texas oil production in the first nine months of 2011. Bakken and East Texas oil sales during the nine months ended September 30, 2012 was $7.7 million and $5.3 million, respectively.
NGL production for the nine months ended September 30, 2012 decreased to 213,726 Bbls compared to 230,385 Bbls for the nine months ended September 30, 2011, a decrease of 7%. This decrease was due primarily to a change in the dispatch of our natural gas to plants with higher NGL recoveries and plant efficiencies, which first became available to us in April 2011 and continued to expand their capacity to process our gas throughout 2011. This was partially offset by the Company's decision in June to sell a portion of our unprocessed gas in the Carthage Texas area for a total price that was greater than the combined estimated price of residue gas and the net processing upgrade. Since the NGLs can be left in or extracted from the gas stream, we will continue to make gas dispatch decisions based on maximizing the total sales value of the combined hydrocarbon stream.
For the nine months ended September 30, 2012, as a result of hedging activities, excluding derivative ineffectiveness, we recognized an increase in natural gas sales of $14.1 million compared to an increase in natural gas sales of $13.1 million in the nine months ended September 30, 2011. For the nine months ended September 30, 2012, hedging, excluding ineffectiveness, increased the average natural gas sales price by $1.80 per Mcf compared to an increase in natural gas sales price of $0.77 per Mcf in the nine months ended September 30, 2011. The increase in natural gas sales and sales price, as a result of hedging activities for the nine months ended September 30, 2012, was mainly due to the amortization of 13.5 million of realized non-cash gain on our cash flow hedges that we monetized in the fourth quarter 2011. Our derivative contracts that have not been monetized on natural gas increased our natural gas sales by $0.1 million and $13.1 million for the nine months ended September 30, 2012 and 2011, respectively. Our derivative contracts on oil increased our oil sales by $0.6 million and decreased our oil sales by $44,000 for the nine months ended September 30, 2012 and 2011, respectively. The effect of our derivative contracts on oil increased the average oil sales price by $3.83 per Bbl for the nine months ended September 30, 2012 and decreased it by $0.67 per Bbl for the nine months ended September 30, 2011.
Lease Operations. Lease operations expense increased $0.3 million, or 3%, for the nine months ended September 30, 2012, to $9.3 million, compared to $9.0 million for the nine months ended September 30, 2011. Lease operations expense on a per Mcfe basis, excluding VPP volumes increased $0.47, or 98%, to $0.95 for the nine months ended September 30, 2012 compared to $0.48 for the nine months ended September 30, 2011. The increase in lease operating expenses in total and on a

33


per Mcfe basis is due to higher lease operating expenses related to the Company's Bakken oil production and the impact of the VPP of $0.23 per Mcfe. For the nine months ended September 30, 2012, lease operations expense on a per Mcfe basis for East Texas and the Bakken was $0.87 and $2.25, respectively.
Production and Severance Taxes. The State of Texas grants an exemption of severance taxes for wells that qualify as “high cost” wells. Certain wells, including all of our H/B wells, qualify for full severance tax relief for a period of ten years or recovery of 50% of the cost of drilling and completions, whichever is less. As a result, refunds for severance tax paid to the State of Texas on wells that qualify for reimbursement are recognized as accounts receivable and offset severance tax expense for the amount refundable. Production and severance taxes decreased 5% to $0.8 million in the nine months ended September 30, 2012 compared to $0.9 million in the nine months ended September 30, 2011. The decrease in production and severance taxes is primarily due to a decrease in revenue as a result of less production and lower oil and natural gas prices compared to the same period in 2011.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $19.7 million, or 49%, to $20.4 million in the nine months ended September 30, 2012 compared to $40.1 million for the nine months ended September 30, 2011. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.63 per Mcfe in the nine months ended September 30, 2012 compared to $1.90 per Mcfe in the nine months ended September 30, 2011. This decrease in the rate per Mcfe is primarily due to the recent impairment charges recognized by the Company which has lowered the amount of oil and gas properties subject to amortization.
        Impairment of oil and natural gas properties and assets held for sale. Of the $166.2 million impairment charge recorded in the nine months ended September 30, 2012, $166.3 million was related to the impairment of oil and gas properties subject to the full cost ceiling test, which was offset by a gain of $0.1 million on the sale of assets held for sale. The primary factors impacting the full cost method ceiling test are expenditures added to the full cost pool, reserve levels, value of cash flow hedges, and natural gas and oil prices, and their associated impact on the present value of estimated future net revenues. Any excess of the net book value is generally written off as an expense. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Natural gas represented approximately 78% of the Company’s total production for the nine months ended September 30, 2012. During the nine months ended September 30, 2012, the 12-month average of the first day of the month natural gas price decreased 32% from $4.12 per MMbtu at December 31, 2011 to $2.82 per MMbtu at September 30, 2012, contributing to the impairment for the nine months ended September 30, 2012. Of the $166.3 million impairment of oil and gas properties, $128.1 million was related to the decrease in natural gas and oil prices and $38.2 million was related to continued infrastructure and operational constraints impacting proved producing reserves in the Bakken. The Company anticipates positive reserve revisions in the future.
    General and Administrative Expense. General and administrative expense for the nine months ended September 30, 2012 was $19.2 million, compared to $22.3 million for the nine months ended September 30, 2011, a decrease of $3.1 million, or 14%. The decrease in general and administrative expense is a result of cost cutting measures implemented by the Company in early 2012. General and administrative expenses include $3.2 million and $2.9 million of non-cash compensation expense as of the nine months ended September 30, 2012 and 2011, respectively. Non-cash compensation represented 17% and 13% of total general and administrative expenses, for the nine months ended September 30, 2012 and 2011, respectively. General and administrative expense has not historically varied in direct proportion to oil and natural gas production because certain types of general and administrative expenses are non-recurring or fixed in nature.
Interest. Interest expense for the nine months ended September 30, 2012 was $30.9 million compared to $23.5 million for the same period in 2011, an increase of $7.4 million or 31%. The increase in interest expense was primarily due to the Company's decision in 2012 to elect the PIK Election on its Senior Secured Notes due 2017 that allows for a 9% cash interest payment along with a 4% interest payment in the form of additional Senior Secured Notes resulting in an annual interest rate of 13%, as well as, the increase in the amount of the outstanding debt between the periods as a result of the exchange offer completed in December 2011. As part of the exchange, certain parties purchased an additional $100 million of the Senior Secured Notes, for a total issuance of $283.5 million of the new Senior Secured Notes due 2017. For the nine months ended September 30, 2011, the Company did not have any outstanding Senior Secured Notes due 2017 and incurred a lower interest expense relating to its then-outstanding indebtedness.
For the nine months ended September 30, 2012 and 2011, interest expense includes non-cash interest expense of $3.4 million and $4.3 million, respectively, related to the accounting for convertible bonds, our share lending agreement and deferred premiums on derivative instruments. Cash interest expense for the nine months ended September 30, 2012 and 2011 was $24.6 million and $22.0 million, respectively, of which $8.8 million and $5.5 million, respectively, was capitalized to properties not subject to amortization on the consolidated balance sheets. Interest associated with the PIK Election was $8.9 million for the nine months ended September 30, 2012. The increase in cash and PIK Election interest expense of $2.6 million

34


was mainly due to the Company's completion of an exchange offer in December 2011, for all but $2.0 million of the 11.375% Senior Notes due 2019 which resulted in $288.6 million of new Senior Secured Notes due 2017. The increase in interest expense was partially offset by the reduction in the 5.00% Convertible Notes during 2012.
Income Taxes. Income tax expense for the nine months ended September 30, 2012 was $4.7 million as compared to $0.5 million in the same period in 2011. The income tax expense recognized in the nine months ended September 30, 2012 and 2011, respectively, was a result of a change in the valuation allowance on net deferred tax assets caused by a change in deferred tax liabilities primarily related to gains on derivative contracts designated as hedges where the mark-to-market change on the hedges, net of deferred taxes, is recorded to other comprehensive income.
Net income to non-controlling interest. Net income to non-controlling interest was $2.8 million for the nine months ended September 30, 2012 compared to $4.3 million for the nine months ended September 30, 2011. This decrease was due to lower natural gas production in East Texas.
Net Loss and Net Loss Per Share
Net Loss and Net Loss Per Share—Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011. For the three months ended September 30, 2012, we reported a net loss applicable to common shareholders of $60.0 million, and for the three months ended September 30, 2011 we reported a net loss applicable to common shareholders of $68.9 million. Net loss per basic and fully diluted share was $0.82 for the third quarter of 2012 compared to net loss per basic and fully diluted share of $1.21 for the third quarter of 2011.
Net Loss and Net Loss Per Share—Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011. For the nine months ended September 30, 2012, we reported a net loss applicable to common shareholders of $206.7 million, and for the nine months ended September 30, 2011 we reported a net loss applicable to common shareholders of $138.8 million. Net loss per basic and fully diluted share was $3.02 for the nine months ended September 30, 2012 compared to net loss per basic and fully diluted share of $2.69 for the nine months ended September 30, 2011.
Capital Resources and Liquidity
Our business is capital intensive. Our ability to grow our production and reserve base is dependent upon our ability to obtain outside capital and generate cash flows from operating activities to reinvest in our drilling programs. Our cash flows from operating activities are substantially dependent upon crude oil and natural gas prices, and significant decreases in market prices of crude oil or natural gas will result in reductions of cash flow which will impact our oil development plans. To mitigate a portion of our exposure to fluctuations in oil and natural gas prices, we have historically entered into swaps, three-way collars and put spreads. We plan to continue to hedge oil and natural gas in the future to mitigate our commodity price risk. For a discussion of our derivative activity, please also see “Quantitative and Qualitative Disclosures About Market Risk” and Note C to the notes to unaudited financial statements included in this report
As of September 30, 2012, we had cash and cash equivalents of $17.9 million, including $2.3 million in restricted cash. Through the period ended September 30, 2012, we have funded our operating expenses and capital expenditures through revenues and from capital raised in December of 2011, which included $100 million from a bond exchange of our 11.375% Senior Noted due 2019 for our new Senior Secured Notes due 2017, $49.7 million from the sale of a VPP, and $18.5 million from the December 2011 monetization of the Company's then existing hedge portfolio.
We continually review our drilling plans and may change the amount we spend based on industry and market conditions and the availability of capital. In the first nine months of 2012, our cash outlay for capital expenditures was $74.3 million. We anticipate funding approximately $110.0 million of cash capital expenditures in 2012 with cash on hand and the $66.7 million in net proceeds from the sale of the Company's East Texas Cotton Valley Sands assets. In October 2012, we closed on the sale of our East Texas Cotton Valley Sand assets, the proceeds of which will be used to fund our 2012 and a portion of our 2013 capital expenditure budget. Our 2012 and 2013 capital expenditure budget will focus on our Middle Bakken development plans particularly in McKenzie and Billings Counties of North Dakota. In the Bakken, we are currently running one drilling rig. In the Niobrara, the Company is planning on drilling two horizontal wells in the Niobrara during 2013. The Company's drilling plan is contingent upon liquidity and operational results.

35


On September 19, 2012, the Company issued (i) $24.9 million aggregate principal amount of Senior Secured Second-Priority Notes and 7,176,384 shares of common stock in exchange for $24.9 million aggregate principal amount of our 5.00% Convertible Notes and (ii) $26.5 million aggregate principal amount of Senior Secured Second-Priority Notes in exchange for $38.0 million aggregate principal amount of our 4.50% Convertible Notes.
During the first the first nine months of 2012, we entered into separate exchange agreements with various holders of our 5.00% Convertible Notes. Pursuant to these agreements, as consideration for the surrender by the holders of $20.8 million aggregate principal amount of the 5.00% Convertible Notes, we issued to the holders an aggregate of 11,271,510 shares of our common stock, par value $0.001 per share (the “Common Stock"), along with cash consideration relating to accrued and unpaid interest. These issuances of the Common Stock were effected pursuant to Section 3(a)(9) of the Securities Act of 1933.
On November 7, 2012, the Company entered into separate commitment agreements (each a “Commitment Agreement” and collectively the “Commitment Agreements”) with several holders (the “Committed Holders”) of the Company's Senior Secured Notes (the “Existing Notes”), issued pursuant to the Indenture dated as of December 19, 2011 among the Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee and Collateral Agent (the “Senior Secured Notes Indenture”). Subject to, and in accordance with, the terms and conditions contained in these Commitment Agreements, each of the Committed Holders have agreed, among other things, to grant the Company the option to cause the Committed Holders to purchase from the Company in a private placement (i) an aggregate of $30.0 million principal amount of additional Senior Secured Notes (to be designated as a new series, the “Additional Notes”) and (ii) an aggregate of 5,942,034 newly-issued shares of common stock at a price equal to $0.48 per share. The Company understands that Committed Holders hold in the aggregate approximately 72% of the outstanding principal amount of the Existing Notes.
As consideration for the Committed Holders' obligations pursuant to the Commitment Agreements, the Company has agreed to pay to each Committed Holder a cash fee equal to 3.0% of the funded principal amount of the New Notes purchased by such Committed Holder and, upon closing of the Private Placement, to issue to each Committed Holder, for a purchase price per share of $0.01, 334.574 shares of Common Stock for each $1,000 principal amount of New Notes purchased by such Committed Holder.
The closing of the transactions is subject to the completion of definitive documents, the consents of holders of at least a majority of Existing Notes to certain proposed amendments to the Senior Secured Notes Indenture, obtaining all necessary consents and approvals from requisite governmental authorities and third parties, as well as other customary closing conditions. 
Cash Flow—Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011
In the nine months ended September 30, 2012 and 2011, we spent $74.3 million and $228.6 million, respectively, in oil and natural gas acquisitions and development activities and related property and equipment, net of proceeds received from sales. These investments were funded during the nine months ended September 30, 2012 by cash on hand and from capital raised in December of 2011 which included $100 million from a bond exchange of our 11.375% Senior Notes for our new Senior Secured Notes, $49.7 million in connection with the VPP, and $18.5 million from the monetization of the Company's hedge portfolio. Cash flow provided by (used in) operating activities in the nine months ended September 30, 2012 was $(5.4) million compared to $48.1 million in the nine months ended September 30, 2011.
Other Debt
Convertible Notes. In February 2008, we issued $125 million of 5.00% Convertible Notes due 2013. The interest on the 5.00% Convertible Notes is payable semi-annually in arrears on February 1 and August 1 of each year, beginning August 1, 2008. As a result of the amortization of the debt discount through non-cash interest expense, the effective interest rate on the 5.00% Convertible Notes is 7.63% per annum.
In March 2011, we completed a tender offer and the Company retired $50 million aggregate principal amount of the 5.00% Convertible Notes. During the first six months of 2012, we entered into separate exchange agreements with various holders of our 5.00% Convertible Notes due 2013. Pursuant to these agreements, as consideration for the surrender by the holders of $20.8 million aggregate principal amount of the 5.00% Convertible Notes, we issued to the holders an aggregate of 11,271,510 shares of our Common Stock, along with cash consideration relating to accrued and unpaid interest. These issuances of Common Stock were effected pursuant to Section 3(a)(9) of the Securities Act of 1933. In addition, on September 19, 2012, the Company issued $24.9 million aggregate principal amount of Senior Secured Second-Priority Notes due 2018 and 7,136,384 shares of common stock in exchange for $24.9 million aggregate principal amount of our 5.00% Convertible Notes due 2013.
On November 7, 2012, the Company reached agreements with certain holders of the Company's existing Senior Secured Notes to provide financing commitments for use to retire the remaining $27.1 million principal amount of the 5.00%

36


Convertible Notes outstanding as of September 30, 2012, by issuing $30.0 million principal amount of new Senior Secured Notes.
In October 2009, the Company issued $86.25 million of 4.50% Convertible Notes due 2015. On September 19, 2012, the Company issued $26.5 million aggregate principal amount of Senior Secured Second-Priority Notes due 2018 in exchange for $38.0 million aggregate principal amount of our 4.50% Convertible Notes due 2015. The $48.3 million of outstanding 4.50% Convertible Notes mature in May 2015, and bear interest at a rate of 4.50% per year, payable semi-annually in arrears on November 1 and May 1 of each year, beginning May 1, 2010. As a result of the amortization of the debt discount through non-cash interest expense, the effective interest rate on the 4.50% Convertible Notes is 8.10% per annum.
We were in compliance with the terms of the 5.00% Convertible Notes and the 4.50% Convertible Notes as of September 30, 2012. For further discussion of our convertible notes, please also read Note B to the notes to unaudited financial statements included in this report.
Senior Notes. On February 9, 2011, we successfully completed the issuance and sale of $200,000,000 aggregate principal amount of 11.375% Senior Notes due 2019. In December 2011, 99% of the 11.375% Senior Notes were converted to new Senior Secured Notes due 2017, which resulted in $1,970,000 of 11.375 % Senior Notes outstanding as of December 31, 2011. All covenants were terminated upon the conversion. We were in compliance with the terms of the 11.375% Senior Notes at September 30, 2012. For further discussion of our 11.375% Senior Notes, please also read Note B to the notes to unaudited financial statements included in this report.
Senior Secured Notes due 2017. On December 19, 2011, the Company executed an Indenture among the Company, the guarantors party thereto and U.S. Bank National Association, as trustee. As a result, the Company issued $283,475,000 aggregate principal amount of Senior Secured Notes due 2017 pursuant to the Senior Secured Notes Indenture. The Senior Secured Notes are fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by each of the Company's existing and future domestic restricted subsidiaries (the “Guarantors”). All of the Company's existing subsidiaries other than Endeavor Gathering, LLC are domestic restricted subsidiaries and Guarantors.
Under the terms of the Senior Secured Notes Indenture, interest on the Senior Secured Notes will:
accrue from the date of issuance of the Senior Secured Notes or, if interest has already been paid, from the most recent interest payment date;
unless the Company makes a PIK Election with respect to an interest period, accrue for such interest period at the rate of 11.0% per annum, payable in cash, in arrears;
if the Company makes a PIK Election with respect to an interest period, accrue for such interest period at the rate of 13.0% per annum in the aggregate, of which (i) 9.0% per annum shall be payable in cash, in arrears, and (ii) 4.0% per annum shall be payable in the form of additional notes (in minimum denominations of $1,000 and integral multiples thereof, with any fractional additional notes being paid in cash), in arrears;
be payable on each June 1 and December 1, commencing June 1, 2012, to holders of record of the Senior Secured Notes as of the May 15 and November 15 immediately preceding the relevant interest payment date; and
be computed on the basis of a 360-day year comprised of twelve 30-day months.
For the interest payment due June 1, 2012, the Company chose the PIK Election and as a result issued $5.1 million of additional Senior Secured Notes as part of the interest payment to bring the outstanding principal balance to $288.6 million as of June 30, 2012. The Company has selected the PIK election for the interest payment due December 1, 2012. The record date for this interest payment is November 15, 2012. The PIK election will increase the outstanding principal balance of the 2017 Senior Secured Notes by $5.8 million.
The Senior Secured Notes will mature on December 1, 2017 and will be secured by first-priority perfected liens on substantially all right, title and interest in or to substantially all of the assets and properties owned or acquired by the Company and the Guarantors (the “Collateral”) The Collateral obligations are governed by, among other security documents, the Security Agreements.
The Senior Secured Notes Indenture restricts, among other things, the Company’s and its restricted subsidiaries’ ability to:
incur or guarantee additional indebtedness or issue certain preferred stock;

37


pay dividends or make other distributions;
issue capital stock of our restricted subsidiaries;
transfer or sell assets, including the capital stock of our restricted subsidiaries;
make certain investments or acquisitions;
grant liens on our assets;
incur dividend or other payment restrictions affecting our restricted subsidiaries;
enter into certain transactions with affiliates; and
merge, consolidate or transfer all or substantially all of our assets.
The covenants are subject to important exceptions and qualifications.
We were in compliance with the terms of the Senior Secured Notes at September 30, 2012. For further discussion of our Senior Secured Notes, please also read Note B to the notes to unaudited financial statements included in this report.
Senior Secured Second Priority Notes due 2018. On September 19, 2012, the Company issued (i) $24,918,000 aggregate principal amount of Senior Secured Second-Priority Notes and 7,136,384 shares of common stock in exchange for $24,918,000 aggregate principal amount of our 5.00% Convertible Notes and (ii) $26,540,000 aggregate principal amount of Senior Secured Second-Priority Notes in exchange for $37,954,000 aggregate principal amount of our 4.50% Convertible Notes.
Interest is payable quarterly on December 2, March 2, June 2 and September 2, commencing March 2, 2013. The Company has the option to pay interest in cash or common stock through September 19, 2014. Subsequent to September 19, 2014, the option to pay interest in common stock expires and all interest payments must be paid in cash only. Interest on the Senior Secured Second-Priority Notes will accrue at an interest rate of 9.00% per annum if the Company chooses to pay the interest in cash or 12.00% per annum if the Company chooses to pay the interest in common stock.
The Senior Secured Second-Priority Notes are secured by second-priority perfected liens on all of the assets and properties owned or acquired by the Company.
The Senior Secured Second-Priority Notes indenture restricts, among other things, the Company’s and its restricted subsidiaries' ability to:
incur or guarantee additional indebtedness or issue certain preferred stock;
pay dividends or make other distributions;
issue capital stock of our restricted subsidiaries;
transfer or sell assets, including the capital stock of our restricted subsidiaries;
make certain investments or acquisitions;
grant liens on our assets;
merge, consolidate or transfer all or substantially all of our assets.
Working Capital
As of September 30, 2012, we had a working capital deficit of $48.2 million. Included in current liabilities is $26.9 million related to the carrying value of the 5.00% Convertible Senior Notes. As mentioned above, on November 7, 2012, the Company reached agreements with certain holders of the Company's existing Senior Secured Notes to provide financing commitments for use to retire the remaining $27.1 million principal amount of the 5.00% Convertible Notes outstanding as of September 30, 2012, by issuing $30.0 million principal amount of new Senior Secured Notes. In October 2012, we closed on the sale of our East Texas Cotton Valley Sand assets for $69.0 million, the proceeds of which will be used to fund our 2012 and a portion of our 2013 capital expenditure budget.
Price Risk Management

38


See Part I, Item 3 – Quantitative and Qualitative Disclosure about Market Risk.
Critical Accounting Policies
Our critical accounting policies are summarized in our 2011 Form 10-K. There have been no changes in such policies.
Contractual Obligations
Our contractual obligations are summarized in our 2011 Form 10-K.
Recently Issued Accounting Standards
See Note A to our financial statements included in Part I, Item 1 of this quarterly report.
Off-Balance Sheet Arrangements
We do not currently have any off-balance sheet arrangements.

39


Forward-Looking Statements
All statements made in this document other than purely historical information are “forward looking statements” within the meaning of the federal securities laws. These statements reflect expectations and are based on historical operating trends, proved reserve positions and other currently available information. Forward-looking statements include statements regarding future plans and objectives, future exploration and development expenditures, the number and location of planned wells, the quality of our properties and potential reserve and production levels, and future revenue and cash flow. These statements may be preceded or followed by or otherwise include the words “believes”, “expects”, “anticipates”, “intends”, “continues”, “plans”, “estimates”, “projects”, “guidance” or similar expressions or statements that events “will” “should”, “could”, “might” or “may” occur. Except as otherwise specifically indicated, these statements assume that no significant changes will occur in the operating environment for oil and gas properties and that there will be no material acquisitions or divestitures except as otherwise described.
The forward-looking statements in this report are subject to all the risks and uncertainties which are described in our 2011 Form 10-K and in this document. We may also make material acquisitions or divestitures or enter into financing transactions. None of these events can be predicted with certainty or taken into consideration in the forward-looking statements.
Including, but not limited to, all of these reasons, actual results may vary materially from the forward looking statements and we cannot assure you that the assumptions used are necessarily the most likely. We will not necessarily update any forward looking statements to reflect events or circumstances occurring after the date the statement is made except as may be required by federal securities laws.

40


ITEM 3.
Quantitative and Qualitative Disclosures About Market Risk.
Commodity Price Risk
We are subject to price fluctuations for natural gas and crude oil. Prices received for natural gas and crude oil sold on the spot market are volatile due to factors beyond our control. Decreases in crude oil and natural gas prices could have a material adverse effect on our financial position, results of operations, capital expenditures and quantities of reserves recoverable on an economic basis.
To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into financial price risk management activities with respect to a portion of projected crude oil and natural gas production through financial price commodity swaps, collars and put spreads.
The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted in 2010 (the “Dodd-Frank Act”) provides for new statutory and regulatory requirements for swaps and other financial derivative transactions, including oil and gas hedging transactions. Under the Dodd-Frank Act, we will be required to submit for clearing on a Designated Clearing Organization (“DCO”) swaps that are required to be cleared. Transactions in swaps subject to the clearing requirement must be executed on a Designated Contract Market (“DCM”) or a Swap Execution Facility (“SEF”), such as a futures exchange or board of trade registered with the Commodity Futures Trading Commission (“CFTC”), if a board of trade or SEF makes the swap available for trading and the swap is not subject to the clearing exception available for swaps used by non-financial entities (as defined in the Dodd-Frank Act) to hedge their commercial risks.  All counterparties to swaps are subject to recordkeeping and reporting requirements for swaps, including swaps that are not subject to clearing on a DCO and are therefore executed on an over-the-counter, bi-lateral basis, and to additional cash collateral or margin requirements.  The Dodd-Frank Act requires the CFTC to impose limits on the positions, other than bona fide hedge positions, that a person may hold with respect to futures contracts relating to physical commodities or options on such contracts or commodities traded on or subject to the rules of a DCM.
The Dodd-Frank Act requires the CFTC, the SEC and, to a limited extent, federal regulators of banks and other financial institutions (the “Prudential Regulators”), to promulgate rules implementing the new law. The CFTC and the SEC have adopted substantial numbers of the rules required to implement the Dodd-Frank Act's provisions, many of which are now effective. Those agencies and the Prudential Regulators have also proposed other implementing rules, which they are in the process of adopting. The CFTC has issued a number of exemptive and no-action letters providing time-limited and other relief from compliance with certain rules and delaying the application of a number of the rules.
Although the CFTC had issued final position limits rules as required by the Dodd-Frank Act, on September 28, 2012, a federal district court vacated those rules. The CFTC has not appealed the court's ruling or made any public statement regarding whether it will appeal that ruling or, instead, will propose revised rules.
The CFTC has adopted final rules that address how swap data will be reported to swap data repositories or the CFTC and how that data will be separately reported to the public.  Two series of rules establish recordkeeping requirements and a regulatory reporting regime for swap markets, in one case as to swaps entered into prior to certain dates and, in the other, swaps entered into after the latest of such dates.  A third series of rules establishes a reporting regime for the public dissemination of swap transaction data in real-time.  All of those rules affect swap dealers, major swap participants, swap counterparties that are neither swap dealers or major swap participants including end-users, swap data repositories, SEFs, DCMs and DCOs.  While we do not believe the internal costs of reporting will be material to us, we have not been able to assess the full impact of these rules on our counterparties and our marketing and hedging activities.  Costs of compliance by our counterparties, particularly with the use of pass through hedge exemptions, will likely be passed on to customers such as ourselves, thus decreasing the benefits to us of hedging transactions and reducing our profitability.  In addition, the new recordkeeping and reporting rules expose us to the risk of financial penalties or disqualifications of transactions as bona fide hedges due to potential failures in compliance with the documentation requirements.
The CFTC and the Prudential Regulators have proposed rules on margin or collateral requirements, but have not released their final rules. It is possible that the new rules will increase the amount of cash required to support exchange and over-the-counter derivative transactions.  The majority of our financial derivative transactions used for hedging purposes are currently executed and cleared over exchanges that already require the posting of margins or other collateral based on initial and variation margin requirements.  Depending on the rules and definitions adopted by the CFTC, we might in the future be required to provide additional cash margin, new cash collateral or other collateral for our commodities hedging transactions whether cleared over an exchange or over-the-counter.
The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our

41


use of derivatives as a result of legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
The following table summarizes the outstanding crude oil and natural gas derivative contracts we had in place as of September 30, 2012:
Effective Date
 
Maturity Date
 
Notional
Amount
Per
Month
 
Remaining
Notional
Amount as
of September 30, 2012
 
Additional
Put
Options
 
Floor
 
Ceiling
 
Designation under
ASC 815
Natural Gas (MMBtu):












 

10/1/2012

12/31/2012

413,659

1,240,978



$2.60

$2.60

Not designated
10/1/2012

12/31/2012

95,541

286,622



$2.50

$3.20

Not designated
1/1/2013

12/31/2013

353,559

4,242,710

$2.85

$3.50

$4.00

Not designated
1/1/2013

12/31/2013

82,240

986,876

$3.00

$3.68

$3.68

Not designated
Crude Oil (Bbls):














10/1/2012

12/31/2012

4,030

12,089



$106.40

$106.40

Not designated
10/1/2012

12/31/2012

5,060

15,180



$96.50

$96.50

Not designated
10/1/2012

12/31/2013

2,950

8,850

$90.00

$100.00

$100.00

Not designated
1/1/2013

12/31/2013

3,548

42,579

$65.50

$106.40



Not designated
1/1/2013

12/31/2013

3,194

38,325

$70.00

$90.00



Not designated
1/1/2013

12/31/2013

2,221

26,654



$100.00



Not designated
1/1/2013

12/31/2013

9,151

109,814





$110.00

Not designated
1/1/2014

12/31/2014

2,961

35,528

$80.00

$100.00

$114.10

Not designated
1/1/2014

12/31/2014

1,658

19,893

$75.00

$95.00



Not designated
1/1/2014

12/31/2014

3,042

36,500

$70.00

$90.00



Not designated
All of the above natural gas contracts are settled against NYMEX and all oil contracts are settled against NYMEX Light Sweet Crude. The NYMEX and NYMEX Light Sweet Crude have historically had a high degree of correlation with actual prices received by the Company.
The net fair value of our natural gas and oil derivative contracts in effect at September 30, 2012 was $(0.1) million, of which $0.9 million is classified as a current asset, $0.8 million is classified as a long-term asset, $1.4 million is classified as a current liability and $0.4 million is classified as a long-term liability.
Based on the monthly notional amount for natural gas in effect at September 30, 2012, a hypothetical $0.10 increase in natural gas prices would have decreased the fair value from our natural gas swaps and options by $0.5 million, and a $0.10 decrease in natural gas prices would have increased the fair value from our natural gas swaps and options by $0.5 million. Based on the monthly notional amount for crude oil in effect at September 30, 2012, a hypothetical $1.00 increase would have decreased the fair value of our oil derivatives by $0.1 million and a $1.00 decrease in oil prices would have increased the fair value of our oil derivatives by $0.1 million.
Interest Rate Risk
We terminated our revolving bank credit facility during December 2011, and currently have no indebtedness for borrowed money based on a floating interest rate.
Our $27.1 million of 5.00% Convertible Notes, $48.3 million of 4.50% Convertible Notes, and $2.0 million of 11.375% Senior Notes have fixed interest rates. Our $288.6 million of Senior Secured Notes have an interest rate fixed at either 11.0% per annum or the rate of 13% applicable to a PIK Election. Our $51.5 million of Senior Secured Second-Priority Notes have an interest rate fixed at either 9.00% per annum or a rate of 12.00% per annum if interest is paid in common stock.
ITEM 4.
Controls and Procedures.
Evaluation of disclosure controls and procedures as of September 30, 2012. As of the end of the period covered by this quarterly report, we have evaluated, under the supervision and with the participation of senior management, including our

42


principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15(b) of the Exchange Act. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide us with reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosures. Based on this evaluation, as of the end of the period covered by this report, our principal executive officer and our principal financial officer have concluded that our disclosure controls and procedures were effective.
Our principal executive officer and our principal financial officer do not expect that our disclosure controls or our internal controls will prevent all error and all fraud. The design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be considered relative to their cost. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that we have detected all of our control issues and all instances of fraud, if any. The design of any system of controls also is based partly on certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving our stated goals under all potential future conditions.
Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


43


PART II. OTHER INFORMATION

ITEM 1.
Legal Proceedings.
A putative class action lawsuit was filed by the Northumberland County Retirement System and Oklahoma Law Enforcement Retirement System (collectively, the “Northumberland Plaintiffs”) in the District Court in Oklahoma County, Oklahoma, purportedly on March 10, 2011, against the Company and certain of its officers along with certain underwriters of the Company's July 2008, May 2009 and October 2009 public offerings. Discovery requests and summons were filed and issued in late April 2011. The complaint alleges that the registration statement and the prospectuses for the offerings contained material misstatements and omissions and seeks damages under Sections 11, 12 and 15 of the Securities Act of 1933 of an unspecified equitable relief. Defendants removed the case to federal court on May 12, 2011 and filed motions to dismiss on June 20, 2011. Plaintiffs filed a motion to remand the case to state court on June 10, 2011, and Defendants filed an opposition to that motion. By order dated November 16, 2011, the court denied Plaintiffs' motion to remand. The Court stayed briefing and decision on the motions to dismiss. On February 3, 2012, Plaintiffs moved to be appointed lead plaintiff under the Private Securities Litigation Reform Act. By order dated July 3, 2012, the Court appointed the Northumberland Plaintiffs lead plaintiff. On August 17, 2012, Plaintiffs filed an amended complaint, which is similar to the original complaint except that it drops all claims relating to the 2008 offering because the financial statements incorporated into the July 2008 offering materials were not restated. On October 3, 2012, Defendants filed a motion to dismiss the amended complaint. Plaintiffs' opposition to the motions to dismiss is due November 15, and Defendants' reply is due November 30, 2012. We are currently unable to assess the probability of loss or estimate a range of potential loss, if any, associated with the securities class action case, which is at an early stage.
On August 5, 2011, an individual filed a shareholders' derivative action in the United States District Court for the Western District of Oklahoma, for the Company's benefit, as nominal defendant, against the Company's Chief Executive Officer, President, Chief Financial Officer, and certain members of the Company's board of directors. The complaint alleges breaches of fiduciary duty, waste of corporate assets, and unjust enrichment on the part of each of the named defendants and is premised on substantially the same facts alleged in the above-described securities lawsuit. The complaint seeks unspecified amounts of compensatory damages, implementation of certain corporate governance changes, and disgorgement of compensation and trading profits from the individual defendants, as well as interest and costs, including legal fees from the defendants. The Company is a nominal defendant, and the complaint does not seek any damages against the Company; however, the Company may have indemnification obligations to one or more of the defendants under the Company's organizational documents. On October 17, 2011, the individual defendants and the Company as nominal defendant filed motions to dismiss the complaint for failure to make demand, or in the alternative, to stay the derivative action pending the outcome of the securities lawsuit. The case is currently stayed pending the outcome of the motions to dismiss with respect to the securities lawsuit described above. On March 23, 2012, an additional plaintiff filed a similar derivative action in the United States District Court for the Western District of Oklahoma. The parties agreed to consolidate this case with the existing federal court derivative action. The federal court derivative actions have been consolidated, and the cases are stayed pending the outcome of the motions to dismiss the securities lawsuit described above. We are currently unable to assess the probability of loss or estimate a range of potential loss, if any, associated with this case.
On February 7 and 9, 2012, two individuals filed separate shareholder derivative actions in the District Court of Oklahoma County, in the State of Oklahoma, for the Company's benefit, as nominal defendant, against the Company's Chief Executive Officer, President, Chief Financial Officer, and each member of the Company's board of directors. The petitions assert claims and seek relief similar to those asserted and sought in the federal court derivative action described above. Plaintiffs filed a motion to consolidate the two state court derivative actions, and the court consolidated the two actions. On April 9, 2012, defendants filed a motion to dismiss, a motion to stay, and a motion for protection from discovery. By stipulation dated May 29, 2012, the parties agreed to stay these cases pending the outcome of the motions to dismiss the securities lawsuit described above and to stay discovery. We are currently unable to assess the probability of loss or estimate a range of potential loss, if any, associated with this case.
The Company is party to various legal actions arising in the normal course of business. Matters that are probable to have an unfavorable outcome to the Company and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, the Company's estimates of the outcomes of such matters, and its experience in contesting, litigating, and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to the Company's financial position or results of operations after consideration of recorded accruals.

44


ITEM 1A.Risk Factors.
Except as set forth below, there have been no material changes in the risk factors applicable to us from those disclosed in our 2011 Form 10-K.
Our future performance depends on our ability to raise equity capital.
As of September 30, 2012, we had approximately $15.5 million of cash on hand and, including $26.9 million aggregate principal amount of our 5.00% Convertible Notes due in February 2013, a $48.2 million working capital deficit. While we believe the current fair value of our total assets, including our oil and gas properties, exceeded their book value as of September 30, 2012, our capital as stated in accordance with generally accepted accounting principles indicated a deficit in shareholders' equity, due principally to impairments and net losses recorded. Our future performance will continue to depend on our ability to raise additional equity capital. We expect that lower commodity prices could result in further impairments being recorded on our assets, which could constrain our ability to incur, or affect the pricing of, additional debt or equity financings, which could adversely affect our ability to operate our business, including drilling and proving up additional recoverable reserves.
Our ability to repay our 5.00% Convertible Notes due in February 2013 with cash is also limited under the indenture for our Senior Secured Notes, and these limitations may require us to issue equity in order to pay cash for, or to otherwise satisfy, the payment of such notes at or prior to their maturity. To the extent required to repay our 5.00% Convertible Notes, our inability to issue sufficient equity could result in a default of our obligations under these notes and/or have a material adverse impact on our financial condition and liquidity. Similarly, the issuance of equity to meet our obligations under these or other notes could have a dilutive and adverse impact on our common stock.
We may not be able to generate enough cash flow to meet our debt obligations.
We expect our earnings and cash flow to vary significantly from year to year due to the nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and other commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt obligations. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control.
The sale of certain of our producing Cotton Valley oil and gas properties in October 2012 will also reduce our near-term operating cash flows as we redeploy proceeds from that sale to planned capital expenditures on our Bakken oil properties.
If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:
selling assets;
reducing or delaying capital investments;
seeking to raise additional capital; or
refinancing or restructuring our debt.
If for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable, which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements. In addition, the trustee or noteholders of our Senior Secured Notes could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on our unsecured notes. If amounts outstanding under our secured and unsecured notes were to be accelerated, we cannot be certain that our assets would be sufficient to repay in full the money owed to the debt holders, or to holders of our 9.25% Series B Cumulative Preferred Stock. Please see “Part 1, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity.”


45


The derivatives legislation adopted by the U.S. Congress and related rules adopted and proposed to be adopted by federal regulators could have an adverse effect on our ability to use derivative contracts to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted in July 2010, or the Dodd-Frank Act, establishes a new regulatory framework for derivative transactions (generally referred to as “swaps”), including oil and gas hedging transactions and interest rate swaps. As required by the Dodd-Frank Act, the Commodity Futures and Trading Commission, or CFTC, federal regulators of banks and other financial institutions, or the prudential regulators, and the SEC have adopted certain rules, and are in the process of adopting other rules, implementing the new law. Until all of these rules are adopted, effective and implemented in practice, we cannot determine the exact impact the new regulatory framework will have on our business.
Swaps designated by, and swaps within classes of swaps designated by, the CFTC will be required to be submitted for clearing on a derivatives clearing organization and, if accepted for clearing, cleared on such organization. Transactions in swaps accepted for clearing must be executed on an exchange that is a designated contract market or on a swap execution facility if such swaps are made available for trading thereon. We anticipate that we will be required to continue to post cash collateral for any of our swaps, including commodities derivative transactions, that are cleared on an exchange, perhaps in amounts in excess of the collateral we now must post. Posting greater amounts of cash collateral for our cleared swaps could cause liquidity issues for us by reducing our ability to use our cash for capital expenditures or other corporate purposes and, therefore, could reduce our ability to execute strategic hedges to reduce commodity price uncertainty and thus protect cash flows.
The Dodd-Frank Act provides an exception from the clearing requirement that commercial end-users may elect for swaps they enter to hedge or mitigate commercial risks. Moreover, the clearing requirement will not apply to swaps existing at the time the clearing requirement first becomes applicable to swaps of the same class if certain reporting requirements are met as to those swaps. Although we believe that we will be able to take advantage of these exceptions as to most, if not all, of our swaps, if we cannot do so as to any of our swaps, we would have to clear such swaps, which could adversely affect our ability to execute our hedging program efficiently. In addition, the CFTC and the prudential regulators have proposed rules that would impose margin requirements for non-cleared swaps that could require us to post cash or other collateral for non-cleared swaps in certain circumstances. Having to posting cash collateral, rather than other types of collateral, for non-cleared swaps could adversely affect our liquidity.
The banks and other parties who are our contractual counterparties will be required to comply with the Dodd-Frank Act's new requirements, and the costs of their compliance will likely be passed on to customers, including us, thus decreasing the benefits to us of hedging transactions and reducing our cash flows. Moreover, to comply with certain provisions of the Dodd-Frank Act, one or more of our swap counterparties may choose to spin off some of all of their derivative operations to a separate entity, which may not be as creditworthy as our current counterparties. These changes might not only increase costs, but could also reduce the availability of some types of swaps that protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts and potentially increase our exposure to less creditworthy counterparties.
The Dodd-Frank Act requires the CFTC to set limits on the positions, other than bona fide hedge positions, that a person may hold with respect to futures contracts relating to physical commodities or options on such contracts or commodities traded on or subject to the rules of a designated contract market. The CFTC had adopted rules limiting the positions, excluding bona fide hedging positions, that a party could hold for its own account in certain futures contracts, including NYMEX contracts relating to light sweet (WTI) crude oil, New York Harbor gasoline blendstock, New York Harbor heating oil and Henry Hub natural gas, and economically equivalent futures contracts, options contracts, swaps and swaptions in a number of physical commodities or other contracts linked to such futures contracts or the underlying commodities. However, a federal district court recently vacated those rules. The position limits rules that finally become effective may impair our ability to execute strategic hedges to reduce commodity price uncertainty, and, thus, to protect our cash flows.
The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
ITEM 2.
Unregistered Sales of Equity Securities and Use of Proceeds.
See our Current Reports on Form 8-K for sales of unregistered equity securities previously reported during the nine months ended September 30, 2012.

46



ITEM 3.
Defaults Upon Senior Securities.
None.

ITEM 4.
Mine Safety Disclosures.
None.
ITEM 5.
Other Information.
None.

ITEM 6.
Exhibits.
See Exhibit Index, which is incorporated by reference herein.


47


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
GMX RESOURCES INC.
 
 
 
Date:
November 8, 2012
/s/ James A. Merrill
 
 
James A. Merrill
 
 
Chief Financial Officer


48


EXHIBIT INDEX
 
 
 
 
Incorporated by Reference
 
 
Exhibit No.
 
Exhibit Description
 
Form
 
SEC File
No.
 
Exhibit
 
Filing Date
 
Filed
Herewith
3.1(a)
 
Amended and Restated Certificate of Incorporation of GMX Resources Inc.
 
SB-2
 
333-49328
 
3.1
 
11/6/2000
 
 
3.1(b)
 
Amended Certificate of Incorporation of GMX Resources Inc.
 
8-K
 
001-32977
 
3.1
 
5/25/2010
 
 
3.1(c)
 
Amended Certificate of Incorporation of GMX Resources Inc.
 
8-K
 
001-32977
 
3.1
 
5/17/2012
 
 
3.2
 
Amended and Restated Bylaws of GMX Resources Inc.
 
8-K
 
001-32977
 
3.2
 
11/4/2008
 
 
3.3
 
Certificate of Designation of Series A Junior Participating Preferred Stock of GMX Resources Inc.
 
8-K
 
000-32325
 
3.1
 
5/18/2005
 
 
3.4(a)
 
Certificate of Designation of 9.25% Series B Cumulative Preferred Stock
 
8-A12B
 
001-32977
 
4.1
 
8/8/2006
 
 
3.4(b)
 
Certificate of Amendment to the Certificate of Designation of the 9.25% Series B Cumulative Preferred Stock
 
8-K
 
011-32977
 
3.1
 
12/14/2010
 
 
4.1(a)
 
Rights Agreement dated May 17, 2005 by and between GMX Resources Inc. and UMB Bank, N.A., as Rights Agent
 
8-K
 
000-32325
 
4.1
 
5/18/2005
 
 
4.1(b)
 
Amendment No. 1 to Rights Agreement dated February 1, 2008
 
8-A/A
 
001-32977
 
2.1
 
2/21/2008
 
 
4.1(c)
 
Amendment No. 2 to Rights Agreement dated October 30, 2008
 
8-A/A
 
001-32977
 
1
 
11/17/2008
 
 
4.2
 
Indenture dated February 15, 2008, between GMX Resources Inc. and The Bank of New York Trust Company, N.A., as Trustee
 
8-K
 
001-32977
 
4.1
 
2/15/2008
 
 
4.3
 
Registration Rights Agreement dated February 11, 2008, between GMX Resources Inc. and Jefferies Funding LLC
 
8-K
 
001-32977
 
10.4
 
2/15/2008
 
 
4.4(a)
 
Indenture dated October 28, 2009, between GMX Resources Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee
 
8-K
 
001-32977
 
4.1
 
10/28/2009
 
 
4.4(b)
 
Supplemental Indenture dated October 28, 2009, between GMX Resources Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee
 
8-K
 
001-32977
 
4.2
 
10/28/2009
 
 
4.5
 
Indenture dated February 9, 2011, between GMX Resources Inc. and the Bank of New York Mellon Trust Company, N.A., as Trustee
 
8-K
 
001-32977
 
4.1
 
2/9/2011
 
 
4.6
 
First Supplemental Indenture dated December 19, 2011,
between GMX Resources Inc., the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as Trustee
 
8-K
 
011-32977
 
4.8
 
12/19/2011
 
 
4.7
 
Indenture dated December 19, 2011, between GMX Resources Inc., the Guarantors named therein and U.S. Bank, N.A., as Trustee
 
8-K
 
011-32977
 
4.1
 
12/21/2011
 
 
4.8
 
Form of Senior Secured Note due 2017 (included as Exhibit A)
 
8-K
 
011-32977
 
4.1
 
12/21/2011
 
 
4.9
 
Security Agreement, dated as of December 19, 2011 between GMX Resources Inc. and U.S. Bank National Association as Collateral Agent
 
8-K
 
011-32977
 
4.3
 
12/21/2011
 
 
4.10
 
Security Agreement, dated as of December 19, 2011 between Endeavor Pipeline Inc. and U.S. Bank National Association as Collateral Agent
 
8-K
 
011-32977
 
4.4
 
12/21/2011
 
 
 


49


 
 
 
 
Incorporated by Reference
 
 
Exhibit No.
 
Exhibit Description
 
Form
 
SEC File
No.
 
Exhibit
 
Filing Date
 
Filed
Herewith
4.11
 
Security Agreement, dated as of December 19, 2011 between Diamond Blue Drilling Co. and U.S. Bank National Association as Collateral Agent
 
8-K
 
011-32977
 
4.5
 
12/21/2011
 
 
4.12
 
Registration Rights Agreement dated February 9, 2011, between GMX Resources Inc. and Credit Suisse Securities (USA) LLC and Morgan Stanley & Co. Incorporated
 
8-K
 
001-32977
 
4.3
 
2/9/2011
 
 
4.13
 
Registration Rights Agreement dated February 28, 2011 between GMX Resources Inc. and Retamco Operating, Inc.
 
8-K
 
001-32977
 
10.1
 
3/2/2011
 
 
4.14
 
Stockholder and Registration Rights Agreement, dated April 28, 2011, among GMX Resources Inc., Arkoma Bakken, LLC, Long Properties Trust and Reynolds Drilling Co., Inc.
 
8-K
 
001-32977
 
10.1
 
5/4/2011
 
 
4.15
 
Registration Rights Agreement dated as of December 19, 2011, by and among GMX Resources Inc., the Guarantors named therein and the Supporting Holders party thereto
 
8-K
 
001-32977
 
4.6
 
12/21/2011
 
 
4.16
 
Registration Rights Agreement dated as of December 19, 2011, by and among GMX Resources Inc., the Guarantors named therein and the Supporting Holders party thereto
 
8-K
 
001-32977
 
4.7
 
12/21/2011
 
 
4.17
 
Indenture, dated as of September 19, 2012, by and among GMX Resources Inc. and U.S. Bank National Association, as Trustee and Collateral Agent
 
8-K
 
001-32977
 
4.1
 
9/20/2012
 
 
4.18
 
Security Agreement, dated as of September 19, 2012, by and among GMX Resources Inc. and U.S. Bank National Association as Collateral Agent
 
8-K
 
001-32977
 
4.3
 
9/20/2012
 
 
4.19
 
Intercreditor Agreement, dated September 19, 2012, by and among GMX Resources Inc., Diamond Blue Drilling Co., Endeavor Pipeline Inc. and U.S. Bank National Association, as Collateral Agent.
 
8-K
 
001-32977
 
4.4
 
9/20/2012
 
 
12.1
 
Computation of Ratio of Earnings to Fixed Charges and to Combined Fixed Charges and Preference Dividends
 
 
 
 
 
 
 
 
 
*
31.1
 
Rule 13a-14(a) Certification of Chief Executive Officer
 
 
 
 
 
 
 
 
 
*
31.2
 
Rule 13a-14(a) Certification of Chief Financial Officer
 
 
 
 
 
 
 
 
 
*
32.1
 
Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350
 
 
 
 
 
 
 
 
 
*
32.2
 
Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350
 
 
 
 
 
 
 
 
 
*
101.INS
 
XBRL Instance Document
 
 
 
 
 
 
 
 
 
*
101.SCH
 
XBRL Taxonomy Extension Schema
 
 
 
 
 
 
 
 
 
*
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase
 
 
 
 
 
 
 
 
 
*
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase
 
 
 
 
 
 
 
 
 
*
101.LAB
 
XBRL Taxonomy Extension Label Linkbase
 
 
 
 
 
 
 
 
 
*
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase
 
 
 
 
 
 
 
 
 
*


50