GMX RESOURCES INC - FORM 10-Q - August 8, 2011

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EX-10.2 - FORM OF CASH BONUS AWARD AGREEMENT - GMX RESOURCES INCcashbonusawardagreement.htm
EX-10.1(A) - FORM OF NON-EMPLOYEE DIRECTOR RESTRICTED STOCK AWARD AGREEMENT - GMX RESOURCES INCnon-employeerestrictedstoc.htm
EX-10.1(B) - FORM OF EMPLOYEE RESTRICTED STOCK AWARD AGREEMENT - GMX RESOURCES INCemployeerestrictedstockawa.htm
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EX-32.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C. 1350 - GMX RESOURCES INCgmxr-2011630_exx322.htm
EX-31.2 - RULE 13A-14(A) CERTIFICATION OF CHIEF FINANCIAL OFFICER - GMX RESOURCES INCgmxr-2011630_exx312.htm
EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. 1350 - GMX RESOURCES INCgmxr-2011630_exx321.htm
EX-31.1 - RULE 13A-14(A) CERTIFICATION OF CHIEF EXECUTIVE OFFICER - GMX RESOURCES INCgmxr-2011630_exx311.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
______________________________________ 
FORM 10-Q
 ______________________________________ 
(Mark One)
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended June 30, 2011
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from              to             
Commission File Number 001-32977
 ______________________________________ 
GMX RESOURCES INC.
(Exact name of registrant as specified in its charter)
______________________________________ 
Oklahoma
 
73-1534474
(State or other jurisdiction of
incorporation or organization)
 
(IRS Employer
Identification No.)
 
 
One Benham Place, 9400 North Broadway, Suite 600
Oklahoma City, Oklahoma
 
73114
(Address of principal executive offices)
 
(Zip Code)
(Registrants’ telephone number, including area code): (405) 600-0711
______________________________________ 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  o 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  o 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer or a smaller reporting company. See the definitions of “accelerated filer,” “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Check one:
Large accelerated filer
 
o
Accelerated filer
 
x
Non-accelerated filer
 
o  (Do not check if a smaller reporting company)
Smaller reporting company
 
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)    Yes  o    No  x
The number of shares outstanding of the registrant’s common stock as of August 7, 2011 was 60,736,758, which included 2,640,000 shares under a share loan which will be returned to the registrant upon conversion of certain outstanding convertible notes.
GMX Resources Inc.
Form 10-Q
For the Quarter Ended June 30, 2011
TABLE OF CONTENTS
 


2

PART I. FINANCIAL INFORMATION

ITEM 1.
Financial Statements

GMX Resources Inc. and Subsidiaries
Consolidated Balance Sheets
(dollars in thousands, except share data)
(Unaudited)
 
June 30,
2011
 
December 31,
2010
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
4,877

 
$
2,357

Accounts receivable – interest owners
4,325

 
5,339

Accounts receivable – oil and natural gas revenues, net
8,478

 
6,829

Derivative instruments
18,891

 
19,486

Inventories
326

 
326

Prepaid expenses and deposits
1,995

 
5,767

Assets held for sale
18,854

 
26,618

Total current assets
57,746

 
66,722

OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD
 
 
 
Properties being amortized
1,021,610

 
938,701

Properties not subject to amortization
174,021

 
39,694

Less accumulated depreciation, depletion, and impairment
(713,330
)
 
(630,632
)
 
482,301

 
347,763

PROPERTY AND EQUIPMENT, AT COST, NET
68,002

 
69,037

DERIVATIVE INSTRUMENTS
12,148

 
17,484

OTHER ASSETS
13,899

 
6,084

TOTAL ASSETS
$
634,096

 
$
507,090

LIABILITIES AND EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable
$
11,871

 
$
24,919

Accrued expenses
38,684

 
33,048

Accrued interest
11,213

 
3,317

Revenue distributions payable
6,102

 
4,839

Current maturities of long-term debt
26

 
26

Total current liabilities
67,896

 
66,149

LONG-TERM DEBT, LESS CURRENT MATURITIES
341,332

 
284,943

DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS
5,619

 
10,622

OTHER LIABILITIES
7,419

 
7,157

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

 
—

9.25% Series B Cumulative Preferred Stock, 6,000,000 shares authorized, 3,176,734 shares issued and outstanding as of June 30, 2011 and 2,041,169 shares issued and outstanding as of December 31, 2010 (aggregate liquidation preference $79,418,350 as of June 30, 2011 and $51,029,225 as of December 31, 2010)
3

 
2

Common stock, par value $.001 per share – 100,000,000 shares authorized, 59,390,455 shares issued and outstanding as of June 30, 2011 and 31,283,353 shares issued and outstanding as of December 31, 2010
59

 
31

Additional paid-in capital
684,196

 
531,944

Accumulated deficit
(500,616
)
 
(430,784
)
Accumulated other comprehensive income, net of taxes
9,662

 
15,227

Total GMX Resources’ equity
193,304

 
116,420

Noncontrolling interest
18,526

 
21,799

Total equity
211,830

 
138,219

TOTAL LIABILITIES AND EQUITY
$
634,096

 
$
507,090

See accompanying notes to consolidated financial statements.

3

GMX Resources Inc. and Subsidiaries
Consolidated Statements of Operations
(dollars in thousands, except share and per share data)
(Unaudited)
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2011
 
2010
 
2011
 
2010
OIL AND GAS SALES, net of gain or (loss) from ineffectiveness of derivatives of $315, $(1,786), $722 and $(1,257), respectively
$
32,858

 
$
23,213

 
$
62,235

 
$
44,513

EXPENSES:
 
 
 
 
 
 
 
Lease operations
2,836

 
2,243

 
5,733

 
5,354

Production and severance taxes
166

 
315

 
549

 
1,025

Depreciation, depletion, and amortization
13,304

 
8,731

 
26,093

 
15,101

Impairment of oil and natural gas properties and assets held for sale
16,861

 
—

 
65,181

 
—

General and administrative
7,605

 
6,219

 
14,683

 
13,406

Total expenses
40,772

 
17,508

 
112,239

 
34,886

Income (loss) from operations
(7,914
)
 
5,705

 
(50,004
)
 
9,627

NON-OPERATING INCOME (EXPENSES):
 
 
 
 
 
 
 
Interest expense
(7,832
)
 
(4,654
)
 
(15,854
)
 
(8,883
)
Loss on extinguishment of debt
(67
)
 
—

 
(176
)
 
—

Interest and other income
12

 
9

 
282

 
33

Unrealized gain or (loss) on derivatives
5,437

 
107

 
4,992

 
(114
)
Total non-operating expense
(2,450
)
 
(4,538
)
 
(10,756
)
 
(8,964
)
Income (loss) before income taxes
(10,364
)
 
1,167

 
(60,760
)
 
663

INCOME TAX (PROVISION) BENEFIT
(1,436
)
 
(2,369
)
 
(2,868
)
 
3,419

NET (LOSS) INCOME
(11,800
)
 
(1,202
)
 
(63,628
)
 
4,082

Net income attributable to noncontrolling interest
1,746

 
618

 
3,158

 
931

NET (LOSS) INCOME APPLICABLE TO GMX RESOURCES
(13,546
)
 
(1,820
)
 
(66,786
)
 
3,151

Preferred stock dividends
1,837

 
1,157

 
3,047

 
2,313

NET (LOSS) INCOME APPLICABLE TO COMMON SHAREHOLDERS
$
(15,383
)
 
$
(2,977
)
 
$
(69,833
)
 
$
838

(LOSS) EARNINGS PER SHARE – Basic
$
(0.28
)
 
$
(0.11
)
 
$
(1.43
)
 
$
0.03

(LOSS) EARNINGS PER SHARE – Diluted
$
(0.28
)
 
$
(0.11
)
 
$
(1.43
)
 
$
0.03

WEIGHTED AVERAGE COMMON SHARES – Basic
55,660,978

 
28,181,587

 
48,959,825

 
28,140,319

WEIGHTED AVERAGE COMMON SHARES – Diluted
55,660,978

 
28,181,587

 
48,959,825

 
28,140,319

See accompanying notes to consolidated financial statements.



4

GMX Resources Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(dollars in thousands)
(Unaudited)
 
 
Six Months Ended
 
June 30,
 
2011
 
2010
CASH FLOWS DUE TO OPERATING ACTIVITIES
 
 
 
Net income (loss)
$
(63,628
)
 
$
4,082

Depreciation, depletion, and amortization
26,093

 
15,101

Impairment of oil and natural gas properties and assets held for sale
65,181

 
—

Deferred income taxes
2,867

 
(3,389
)
Non-cash compensation expense
2,155

 
3,545

Loss (gain) on extinguishment of debt
176

 
—

Non-cash interest expense
4,622

 
4,545

Non-cash change in fair value of derivative financial instruments
(4,992
)
 
114

Other
(722
)
 
1,257

Decrease (increase) in:
 
 
 
Accounts receivable
(634
)
 
(659
)
Inventory and prepaid expenses
(231
)
 
(79
)
Increase (decrease) in:
 
 
 
Accounts payable and accrued liabilities
5,474

 
(2,340
)
Revenue distributions payable
1,263

 
293

Net cash provided by operating activities
37,624

 
22,470

CASH FLOWS DUE TO INVESTING ACTIVITIES
 
 
 
Purchase of oil and natural gas properties
(192,708
)
 
(76,794
)
Proceeds from sale of oil and natural gas properties, property, equipment and assets held for sale
2,189

 
5,986

Purchase of property and equipment
(1,739
)
 
(6,773
)
Net cash used in investing activities
(192,258
)
 
(77,581
)
CASH FLOWS DUE TO FINANCING ACTIVITIES
 
 
 
Borrowings on revolving bank credit facility
26,000

 
26,000

Payments on debt
(118,035
)
 
(50
)
Payments on 5.00% Senior Convertible Notes
(50,000
)
 
—

Issuance of 11.375% Senior Notes
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
(3,047
)
 
(2,312
)
Fees paid related to financing activities
(16,132
)
 
—

Contributions from non-controlling interest member
385

 
(956
)
Distributions to non-controlling interest member
(6,816
)
 
—

Net cash provided by (used in) financing activities
157,154

 
22,682

NET INCREASE (DECREASE) IN CASH
2,520

 
(32,429
)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
2,357

 
35,554

CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
4,877

 
$
3,125

SUPPLEMENTAL CASH FLOW DISCLOSURE
 
 
 
CASH PAID DURING THE PERIOD FOR:
 
 
 
INTEREST, Net of amounts capitalized
$
3,336

 
$
5,466

INCOME TAXES, Paid (Received)
$
1

 
$
(30
)
NON-CASH INVESTING AND FINANCING ACTIVITIES
 
 
 
Additions to oil and natural gas properties from issuance of common stock
$
31,612

 
$
—

(Increase) decrease in accounts payable for property additions
$
7,079

 
$
(8,648
)
See accompanying notes to consolidated financial statements.

5

GMX Resources Inc. and Subsidiaries
Consolidated Statements of Comprehensive Income
(dollars in thousands)
(Unaudited)
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2011
 
2010
 
2011
 
2010
Net (loss) income
$
(11,800
)
 
$
(1,202
)
 
$
(63,628
)
 
$
4,082

Other comprehensive income (loss), net of income tax:
 
 
 
 
 
 
 
Change in fair value of derivative instruments, net of income tax of $(79), $122, $2, $6,313, respectively
(153
)
 
237

 
3

 
12,254

Reclassification of gain on settled contracts, net of income taxes of ($1,357), ($2,490), ($2,868), ($3,728), respectively
(2,634
)
 
(4,834
)
 
(5,568
)
 
(7,236
)
Comprehensive (loss) income
(14,587
)
 
(5,799
)
 
(69,193
)
 
9,100

Comprehensive income attributable to the noncontrolling interest
1,746

 
618

 
3,158

 
931

Comprehensive (loss) income attributable to GMX shareholders
$
(16,333
)
 
$
(6,417
)
 
$
(72,351
)
 
$
8,169

See accompanying notes to consolidated financial statements.
 

6

GMX Resources Inc.
Condensed Notes To Interim Financial Statements
Three months ended June 30, 2011 and 2010
(Unaudited)

NOTE A – NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Business
GMX Resources Inc. (“GMX”) and its subsidiaries (collectively, the “Company”, “we,” “us” and “our”) is an independent oil and natural gas exploration and production company historically focused on the development of the Cotton Valley group of formations, specifically the Cotton Valley Sands layer in the Schuler formation and the Upper Bossier, Middle Bossier and Haynesville/Lower Bossier layers of the Bossier formation (the “Haynesville/Bossier Shale”), in the Sabine Uplift of the Carthage, North Field of Harrison and Panola counties of East Texas (our “primary development area”).
During 2010, we made a strategic decision to pursue properties that would expand our assets and development into other basins, diversify our company’s concentrated natural gas focus from two resource plays in one basin and provide the Company more liquid hydrocarbon opportunities. These efforts have led to successful agreements entered into during the first half of 2011 to acquire core positions in over 75,000 net acres in two of the leading oil resource plays in the U.S. In January 2011, the Company entered into five transactions to purchase undeveloped leasehold in the very successful and competitive region located in the Williston Basin of North Dakota/Montana, targeting the Bakken/Sanish-Three Forks Formation, and in the oil window of the Denver Julesburg Basin (the “DJ Basin”) of Wyoming, targeting the emerging Niobrara Formation. In May 2011, the Company increased its Williston Basin position with multiple transactions totaling 11,449 net acres. With the acquisition of the liquids-rich (estimated 90% oil) Bakken and Niobrara acreage, we will have better flexibility to deploy capital based on a variety of economic and technical factors, including well costs, service availability, take-away capacity and commodity prices (including differentials applicable to the basin). We believe this flexibility will enable us to generate better cash flow growth to fund our capital expenditure program. We believe our experienced Rockies and Haynesville/Bossier Shale horizontal drilling personnel will enable us to succeed in the development of these new oil resource plays. A summary of the 2011 transactions are as follows:
•
Niobrara acquisition—On February 14, 2011, the company acquired all of the working interest and an 80% net revenue interest in approximately 30,818 undeveloped net acres of oil and gas leases located in the Niobrara basin in Wyoming for approximately $27.4 million, including commissions. Pursuant to our agreement with the seller, the seller has elected not to exercise an option to reacquire 50% of the working interest acquired by us in these properties at the same purchase price paid by us.
•
Bakken acquisition-Retamco—On January 13, 2011, we entered into a purchase and sale agreement relating to the acquisition by the Company of all of the working interest and an 80% net revenue interest in approximately 17,797 undeveloped net acres of oil and gas leases located in the Bakken formation in Montana and North Dakota. Pursuant to this agreement, as consideration for the oil and gas leases, we issued to the seller, Retamco Operating, Inc., at the closing of this transaction on February 28, 2011, 2,268,971 shares of common stock and approximately $4.2 million in cash. At the closing, the Company also entered into a registration rights agreement with this seller relating to the resale of the shares of common stock received in this transaction.
•
Niobrara acquisition-Retamco—On January 13, 2011, we entered into a separate purchase and sale agreement with Retamco Operating, Inc. relating to the acquisition by the Company of all of the working interest and an 80% net revenue interest in approximately 9,374 undeveloped net acres of oil and gas leases located in the Niobrara basin in Wyoming. The purchase price for this transaction was approximately $24.0 million in cash. On April 6, 2011, we completed the purchase of 9,039 acres and the remaining 335 net acres in May 2011.
•
Bakken acquisitions-Arkoma Bakken and other parties—On April 28, 2011, the Company acquired an undivided 87.5% of the sellers’ working interest and an 82.5% net revenue interest in approximately 7,613 undeveloped acres located in McKenzie and Dunn Counties, North Dakota (with the acquired interest representing 6,661 net acres). The aggregate purchase price for these properties was approximately $31.2 million, of which approximately $10.4 million was paid in cash and the remainder of the purchase price was paid with stock consideration of 3,542,091 common shares (based on a 15 day volume weighted average value of $5.88 per share). At closing, the Company entered into a participation agreement with a joint operating agreement designating the Company as the operator of these properties. The Company has entered into a registration rights agreement with these sellers at closing relating to the resale of the shares of common stock received in this transaction. However, these sellers have agreed not to sell the shares of common stock received by them for six months following the closing of this transaction.

7

•
May 2011 Bakken acquisitions - In May 2011, the Company increased its Williston Basin position with multiple transactions totaling 11,449 net acres for a total purchase price of $28 million. The first of two significant transactions was a purchase and sale agreement for 9,608 net acres at an average cost of $2,500 per acre, from a private seller, located in Billings and Stark Counties, ND. The second transaction was for 1,684 net acres from the State of North Dakota at an average cost of $2,211 per acre. Approximately 960 net acres are located in McKenzie County and 724 net acres are located in Billings County. The remaining 157 net acres were acquired through the leasing of several fee mineral rights.
The two Bakken acquisitions in May 2011 bring our total Williston Basin net acres to 35,524. We hold Williston Basin leases in approximately 150 1,280-acre units and expect to be the operator in approximately 43 of those units, providing a minimum of 172 operated locations. We expect that the average working interest in our Williston Basin operated locations to be approximately 45%, with the first three operated wells having an 80%-100% working interest.
We have three subsidiaries: Diamond Blue Drilling Co. (“Diamond Blue”), which owns three conventional drilling rigs, Endeavor Pipeline Inc. (“Endeavor Pipeline”), which operates our water supply and salt water disposal systems in our primary development area, and Endeavor Gathering, LLC (“Endeavor Gathering”), which owns the natural gas gathering system and related equipment operated by Endeavor Pipeline. Kinder Morgan Endeavor LLC (“KME”) owns 40% membership interest in Endeavor Gathering.
Basis of Presentation
The accompanying unaudited consolidated financial statements and condensed notes thereto of GMX have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted. The accompanying consolidated financial statements and notes thereto should be read in conjunction with the audited consolidated financial statements and notes thereto included in GMX’s 2010 Annual Report on Form 10-K (“2010 10-K”).
In the opinion of GMX’s management, all adjustments (all of which are normal and recurring) have been made which are necessary to fairly state the unaudited consolidated balance sheet of GMX as of June 30, 2011, and the results of its operations for the three and six months ended June 30, 2011 and 2010 and its cash flow for the six months ended June 30, 2011 and 2010.
Earnings Per Share
Basic earnings (loss) per common share is computed by dividing the net income (loss) applicable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings (loss) per common share is calculated in the same manner, but also considers the impact to net income (loss) and common shares for the potential dilution from our convertible notes, outstanding stock options and non-vested restricted stock awards. Because the Company was in a loss position for the three and six months ended June 30, 2011, the instruments mentioned above would decrease diluted loss per share, which would result in antidilutive instruments. Therefore, there were no dilutive shares for the three and six months ended June 30, 2011. For the same reason, there were no dilutive shares for the three months ended June 30, 2010 and, due to lower share prices, it was also determined that there were no dilutive shares for the six months ended June 30, 2010.
Oil and Natural Gas Properties
The Company follows the full cost method of accounting for its oil and natural gas properties and activities. Accordingly, the Company capitalizes all costs incurred in connection with the acquisition, exploration and development of oil and natural gas properties. The Company capitalizes internal costs that can be directly identified with exploration and development activities, but does not include any costs related to production, general corporate overhead, or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and gas wells, including salaries and benefits and other internal costs directly attributable to these activities. Also included in oil and natural gas properties are tubular and other lease and well equipment of $3.9 million and $4.1 million at June 30, 2011 and December 31, 2010, respectively, that have not been placed in service but for which we plan to utilize in our on-going exploration and development activities.
Capitalized costs are subject to a “ceiling test,” which limits the net book value of oil and natural gas properties less related deferred income taxes to the estimated after-tax future net revenues discounted at a 10-percent interest rate. The cost of unproved properties is added to the future net revenues less income tax effects. At June 30, 2011 and 2010, future net revenues are calculated using prices that represent the average of the first day of the month price for the 12-month period prior to the end of the period.

8

Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. Based on average prices for the prior 12-month period for natural gas and oil as of June 30, 2011, these cash flow hedges increased the full-cost ceiling by $41.2 million thereby reducing the ceiling test write-down by the same amount. Excluding the effects of the cash flow hedge, which increased the full cost ceiling by $63.3 million, we would have incurred a ceiling test write-down of $61.2 million for the six months ended June 30, 2010. Our natural gas hedging activities are discussed in Note C of these consolidated financial statements
The primary factors impacting the full cost method ceiling test are expenditures added to the full cost pool, reserve levels, value of cash flow hedges and natural gas and oil prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value is generally written off as an expense. Natural gas represents 90% of the Company’s total production, and as a result, a decrease in natural gas prices can significantly impact the Company’s ceiling test. During the first six months of 2011, the 12-month average of the first day of the month natural gas price decreased 4% from $4.38 per MMbtu at December 31, 2010 to $4.21 per MMbtu at June 30, 2011. As a result of the Company’s quarterly ceiling test, the Company recorded impairment expense related to oil and gas properties of $59.6 million through the first six months of 2011.
For the oil and gas impairment charge recorded in the first six months of 2011, $14.5 million of the $59.6 million charge was related to the acquisition cost of undeveloped acreage subject to the impairment test, based on the Company’s decision during the first quarter of 2011 not to develop the acreage before the expiration of the related leases. The Company’s decision not to develop the acreage was based on analysis completed in the first quarter of 2011, after looking at off-set wells, anticipated future gas prices, infrastructure costs, the Company’s liquidity position and focus on exploration and development of the newly acquired acreage in Bakken and Niobrara areas.
Assets held for sale on our consolidated balance sheets are measured at the lesser of carrying value or fair value less cost to sell. Based on our analysis of recent offers to purchase a portion of our assets held for sale for a lower amount than the carrying amount as of June 30, 2011, we estimated that those assets should further be impaired by approximately $5.4 million for the six months ended June 30, 2011.
Recent Accounting Standards
In January 2010, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2010-06, “Improving Disclosures about Fair Value Measurements” (“ASU No. 2010-06”), a standard intended to improve disclosures about fair value measurements. The standard requires additional disclosures about fair value measurements, adding a new requirement to disclose transfers in and out of Levels 1 and 2 measurements and gross presentation of activity within a Level 3 roll forward. The standard also clarified existing disclosure requirements regarding the level of disaggregation of fair value measurements and disclosures regarding inputs and valuation techniques. We adopted all aspects of ASU No. 2010-06 effective as of the first quarter of 2010. The adoption had no impact on our consolidated financial position or results of operations.


9

NOTE B – LONG-TERM DEBT
The table below presents the carrying amounts and approximate fair values of our debt obligations. The carrying amounts of our revolving bank credit facility borrowings approximate their fair values due to the short-term nature and frequent repricing of these obligations. The approximate fair values of our convertible debt securities are determined based on market quotes from independent third party brokers as they are actively traded in an established market.
 
 
June 30, 2011
 
December 31, 2010
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
 
 
 
(in thousands)
 
 
Revolving bank credit facility(1)
$
—

 
$
—

 
$
92,000

 
$
92,000

5.00% Convertible Senior Notes due February 2013
69,845

 
68,203

 
116,365

 
105,258

4.50% Convertible Senior Notes due May 2015
76,325

 
69,863

 
75,238

 
63,825

11.375% Senior Notes due February 2019
193,856

 
186,000

 
—

 
—

Joint venture financing(2)
1,332

 
1,332

 
1,366

 
1,366

Total
$
341,358

 
$
325,398

 
$
284,969

 
$
262,449

 __________________
(1)
Maturity date of January 1, 2013 and collateralized by all assets of the Company.
(2)
Non-recourse, no interest rate.
Revolving Bank Credit Facility
On February 2, 2011, the Company entered into a Fifth Amended and Restated Loan Agreement among the Company, as borrower, Capital One, National Association, as administrative agent, arranger and bookrunner, BNP Paribas, as syndication agent, and the lenders named therein (the “Restated Loan Agreement” or “revolving bank credit facility”). The Restated Loan Agreement became effective after specified conditions had been satisfied, as amended on February 3, 2011, including (i) the completion of an equity offering of at least $75.0 million of common stock and an offering of senior unsecured notes in a principal amount of at least $175.0 million, on terms specified, in each case on or before February 28, 2011, (ii) the deposit of at least $50.0 million of the proceeds from the common stock and senior unsecured notes offerings in a restricted account with the agent on or before the closing date, for use solely for the purpose of retiring a portion of the Company’s 5.00% convertible notes, such that the principal of such notes will be no more than $75.0 million within 45 days after the effective date of the Restated Loan Agreement (with such restricted account and remaining funds continuing as collateral under the Restated Loan Agreement if such debt is not retired to such outstanding balance at such time), and (iii) no advances, unpaid fees or other borrowings are outstanding under the prior loan agreement, excluding letters of credit that will be transferred to be outstanding under the Restated Loan Agreement.
The Restated Loan Agreement will mature on January 1, 2013; provided, that if our 5.00% convertible notes have been repurchased and no longer remain outstanding, the maturity date will be extended automatically to December 31, 2013, assuming we are in compliance with all covenants under the amended revolving bank credit facility.
The Restated Loan Agreement provides for a line of credit of up to $100.0 million (the “commitment”), subject to a borrowing base (“borrowing base”). The initial borrowing base availability under the Restated Loan Agreement is $60.0 million. The amount of loans available at any one time under the Restated Loan Agreement is the lesser of the borrowing base or the amount of the commitment. The borrowing base will be subject to semi-annual redeterminations (approximately April 1 and October 1) during the term of the loan, commencing October 1, 2011, and is based on evaluations of our oil and gas reserves. The Restated Loan Agreement includes a letter of credit sublimit of up to $10.0 million.
On March 14, 2011, the Company entered into an amendment to Restated Loan Agreement, dated effective as of March 31, 2011, which amended certain provisions of the Restated Loan Agreement to (i) extend the period during which GMXR may issuance additional shares of its 9.25% Series B Cumulative Preferred Stock under its at-the-market offering program; (ii) increase the maximum aggregate liquidation preference of such issuances to up to $62.0 million; and (iii) permit the Company to use the cash proceeds from such issuances for general corporate and working capital purposes.
As a result of the Restated Loan Agreement and a decrease in the commitment, we recorded a loss on the extinguishment of debt of $1.9 million, which relates to the write-off of the original debt transaction costs in proportion to the decrease in commitment in the Restated Loan Agreement.

10

The loans under our Restated Loan Agreement bear interest, at the Company's election, at a base rate which is based on the prime rate, LIBOR or federal funds rate plus margins ranging from 1% to 4.00% depending on the base rate used and the amount of loans outstanding in relation to the borrowing base. We may voluntarily prepay the loans without premium or penalty. If and to the extent the loans outstanding exceed the most recently determined borrowing base, the loan excess will be mandatorily pre-payable within 90 days after notice. Otherwise, any unpaid principal or interest will be due and payable at maturity. The Company is obligated to pay a facility fee equal to 0.5% per annum of the unused portion of the borrowing base, payable quarterly in arrears beginning March 31, 2011.
Loans under the Restated Loan Agreement are secured by a first priority mortgage on substantially all of our oil and natural gas properties, a pledge on the Company’s ownership of equity interests in its subsidiaries, a guaranty from Endeavor Pipeline, Inc. and any future subsidiaries of the Company and a security interest in certain of our and the guarantors’ assets.
Our revolving bank credit facility contains various affirmative and restrictive covenants. These covenants, among other things, prohibit additional indebtedness, sales of assets, mergers and consolidations, dividends and distributions, and changes in management and require the maintenance of various financial ratios. The required and actual financial ratios as of June 30, 2011 are shown below:
Financial Covenant
Required Ratio
  
Actual
Ratio
Current ratio(1)
Not less than 1 to 1
  
1.46 to 1
Ratio of total senior secured debt to EBITDA(2)
Not greater than 2.50 to 1
  
0.01 to 1
Ratio of EBITDA (as defined in the revolving bank credit facility agreement) to cash interest expense, including preferred dividends payable under our Series B cumulative preferred stock(3)
Not less than 2.50 to 1
  
2.76 to 1
__________________
(1)
Current ratio is defined in our revolving bank credit facility as the ratio of current assets plus the unused and available portion of the revolving bank credit facility ($60.0 million as of June 30, 2011) to current liabilities. The calculation will not include the effects, if any, of derivatives under FASB Accounting Standards Codification ("ASC") 815, "Derivatives and Hedging." As of June 30, 2011, current assets included derivative assets of $18.9 million. In addition, the 5.00% convertible senior notes due 2013 (the “5.00% convertible notes”) and the 4.50% convertible senior notes due 2015 (the “4.50% convertible notes”) are not considered a current liability unless one or more of such convertible notes have been surrendered for conversion and then only to the extent of the cash payment due on the conversion of the notes surrendered. As of June 30, 2011, none of the 5.00% convertible notes and the 4.50% convertible notes had been surrendered for conversion.
(2)
EBITDA is a non-GAAP number that is defined in our revolving bank credit facility and is calculated and reconciled as follows from the GAAP amount of net loss for the twelve months ended June 30, 2011 (amounts in thousands):
Net loss
$
(206,001
)
Plus:
 
Interest expense
25,613

Impairment of oil and natural gas properties
208,894

Depreciation, depletion and amortization
49,053

Non-cash compensation and other expenses
(5,774
)
Income tax provision
2,049

Less:
 
Gain on extinguishment of debt
35

EBITDA
$
73,869

 
(3)
Cash interest expense is defined in the revolving bank credit facility as all interest, fees, charges, and related expenses payable in cash for the applicable period payable to a lender in connection with borrowed money or the deferred purchase price of assets that is considered interest expense under GAAP, plus the portion of rent paid or payable for that period under capital lease obligations that should be treated as interest. For the twelve months ended June 30, 2011, cash interest expense included fees paid related to bank financing activities and other loan fees of $1.5 million. As of June 30, 2011, non-cash interest expense of $8.0 million was deducted from interest expense to arrive at the cash interest expense used in the debt covenant calculation. Non-cash interest expense primarily relates to the amortization of debt issuance costs and convertible debt discount. Capitalized interest of $4.5 million was added to interest expense.
As of June 30, 2011, the Company was in compliance with all financial covenants under the revolving bank credit facility.

11


5.00% Convertible Senior Notes
As of June 30, 2011 and December 31, 2010, the net carrying amount of the 5.00% convertible notes was as follows (amounts in thousands):
 
 
June 30, 2011
 
December 31, 2010
Principal amount
$
72,750

 
$
122,750

Less: Unamortized debt discount
(2,905
)
 
(6,385
)
Carrying amount
$
69,845

 
$
116,365

The 5.00% convertible notes bear interest at a rate of 5.00% per year, payable semiannually in arrears on February 1 and August 1 of each year, beginning August 1, 2008. As a result of the amortization of the debt discount through non-cash interest expense, the effective interest rate on the 5.00% convertible notes is 8.7% per annum. The amount of the cash interest expense recognized with respect to the 5.00% contractual interest coupon for the three and six months ended June 30, 2011 was $0.9 million and $2.3 million, respectively, and $1.6 million and $3.1 million for the three and six months ended June 30, 2010, respectively. The amount of non-cash interest expense related to the amortization of the debt discount and amortization of the transaction costs for the three and six months ended June 30, 2011 was $0.4 million and $1.1 million, respectively, and $0.9 million and $1.8 million for the three and six months ended June 30, 2010, respectively.

As of June 30, 2011, the unamortized discount is expected to be amortized into earnings over 1.6 years. The carrying value of the equity component of the 5.00% convertible notes was $3.9 million as of June 30, 2011.
On January 28, 2011, the Company announced the commencement of a tender offer for up to $50 million aggregate principal amount of the outstanding 5.00% convertible notes. The tender offer expired March 11, 2011 and the Company retired $50 million aggregate principal amount of the 5.00% convertible notes. This transaction was accounted for under ASC 470-20-40. Under this guidance, the consideration transferred was allocated to the extinguishment of the liability and reacquisition of the original equity component resulting in a gain on extinguishment of debt of $2.1 million and a charge to additional-paid-in-capital of $5.2 million. The gain on the extinguishment of debt in this transaction was offset by the loss on the extinguishment of our revolving bank credit facility noted above plus transactions costs incurred to extinguish the debt, which resulted in a total loss on extinguishment of debt of $0.2 million, including $0.1 million for the three months ended June 30, 2011, presented in our consolidated statements of operations. As of December 31, 2010, unamortized debt issue costs were approximately $9.1 million, with $4.8 million included in other assets and $4.3 million included in current prepaid expenses and deposits. As of June 30, 2011, unamortized costs were $12.2 million, with all costs classified within other assets.

4.50% Convertible Senior Notes
As of June 30, 2011 and December 31, 2010, the net carrying amount of the 4.50% convertible notes was as follows (amounts in thousands):
 

 
June 30, 2011
 
December 31, 2010
Principal amount
$
86,250

 
$
86,250

Less: Unamortized debt discount
(9,925
)
 
(11,012
)
Carrying amount
$
76,325

 
$
75,238

The 4.50% convertible notes bear interest at a rate of 4.50% per year, payable semiannually in arrears on November 1 and May 1 of each year, beginning May 1, 2010. As a result of the amortization of the debt discount through non-cash interest expense, the effective interest rate on the 4.50% convertible notes is 9.09% per annum. The amount of the cash interest expense recognized with respect to the 4.50% contractual interest coupon for the three and six months ended June 30, 2011 was $1.0 million and $1.9 million, respectively, and $1.0 million and $1.9 million for the three and six months ended June 30, 2010, respectively. The amount of non-cash interest expense related to the amortization of the debt discount and transaction costs for the three and six months ended June 30, 2011 was $0.6 million and $1.1 million, respectively, and $0.6 million and $1.2 million for the three and six months ended June 30, 2010, respectively. As of June 30, 2011, the unamortized discount is expected to be amortized into earnings over 3.8 years. The carrying value of the equity component of the 4.50% convertible notes was $8.4 million as of June 30, 2011.



12

11.375% Senior Notes
On February 9, 2011, the Company successfully completed the issuance and sale of $200 million aggregate principal amount of 11.375% Senior Notes due 2019 (the “11.375% senior notes”). The 11.375% senior notes are jointly and severally, and unconditionally, guaranteed (the “guarantees”) on a senior unsecured basis initially by two of our wholly-owned subsidiaries, and all of our future subsidiaries other than immaterial subsidiaries (such guarantors, the “Guarantors”). The 11.375% senior notes and the guarantees were issued pursuant to an indenture dated as of February 9, 2011 (the “Indenture”), by and among the Company, the Guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., a national banking association, as trustee (the “Trustee”). As of June 30, 2011, the net carrying amount of the 11.375% senior notes was as follows (amounts in thousands):
 
 
June 30, 2011
Principal amount
$
200,000

Less: Unamortized debt discount
(6,144
)
Carrying amount
$
193,856

The 11.375% senior notes bear interest at a rate of 11.375% per year, payable semiannually 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 12.00% per annum. The amount of the cash interest expense recognized with respect to the 11.375% contractual interest coupon for the three and six months ended June 30, 2011 was $5.7 million and $9.0 million, respectively. The amount of non-cash interest expense for the three and six months ended June 30, 2011 related to the amortization of the debt discount and transaction costs was $0.4 million and $0.6 million, respectively. As of June 30, 2011, the unamortized discount is expected to be amortized into earnings over 7.6 years.

The Indenture contains covenants that, among other things, limit the Company’s ability and the ability of certain of its subsidiaries to:
•
incur additional indebtedness;
•
issue preferred stock;
•
pay dividends or repurchase or redeem capital stock;
•
make certain investments;
•
incur liens;
•
enter into certain types of transactions with its affiliates;
•
limit dividends or other payments by the Company’s restricted subsidiaries to the Company; and
•
sell assets, or consolidate or merge with or into other companies.
These limitations are subject to a number of important exceptions and qualifications.
Upon an Event of Default (as defined in the Indenture), the Trustee or the holders of at least 25% in aggregate principal amount of the 111.375% senior notes then outstanding may declare the entire principal of all the notes to be due and payable immediately.
At any time on or prior to February 15, 2014, the Company may, at our option, redeem up to 35% of the 11.375% senior notes, including additional notes, with the proceeds of certain public offerings of our common stock at a price of 11.375% of their principal amount plus accrued interest, provided that: (i) at least 65% of the aggregate principal amount of the notes originally issued remains outstanding after the redemption; and (ii) the redemption occurs within 90 days after the closing of the related public offering.
At any time on or prior to February 15, 2015, the Company may, at its option, redeem the 11.375% senior notes at a redemption price equal to 100% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date plus a “make-whole” premium.

13

On or after February 15, 2015, the Company may, at its option, redeem some or all of the 11.375% senior notes at any time at the redemption prices set forth below, plus accrued and unpaid interest, if any, to the redemption date:
 
Year
Percentage
2015
108.531
%
2016
105.688
%
2017
102.844
%
2018 and thereafter
100.000
%
If the Company experiences certain kinds of changes of control, holders of the 11.375% Senior Notes will be entitled to require us to purchase all or a portion of the 11.375% senior notes at 101% of their principal amount, plus accrued and unpaid interest to the date of repurchase.
The purchase price for the 11.375% senior notes and guarantees was 96.833% of their principal amount. The net proceeds from the issuance of the 11.375% senior notes were approximately $187.2 million after discounts and underwriters’ fees.

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 reduce the Company’s borrowing base under the revolving bank credit facility and adversely affect the Company’s liquidity and ability to obtain capital for acquisition and development activities.
To mitigate a portion of its exposure to fluctuations in commodity prices, the Company enters into financial price risk management activities with respect to a portion of projected crude oil and natural gas production through financial price swaps, collars and put spreads (collectively “derivatives”). Additionally, the Company uses basis protection swaps to reduce basis risk. Basis is the difference between the price of the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas due to the geographic price differentials between a given cash market location and the futures contract delivery locations. Settlement or expiration of the hedges is designed to coincide as closely as possible with the physical sale of the commodity being hedged—daily for oil and monthly for natural gas—to obtain reasonable assurance that a gain in the cash sale will offset the loss on the hedge and vice versa.
The Company’s revolving bank credit facility requires the Company to maintain a hedging program on mutually acceptable terms whenever the loan amount outstanding exceeds 75% of the borrowing base. The Company utilizes counterparties for our derivative instruments that are members of our lending bank group and that the Company believes are credit-worthy entities at the time the transactions are entered into. The Company closely monitors the credit ratings of these counterparties. Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. However, the recent events in the financial markets demonstrate there can be no assurance that a counterparty financial institution will be able to meet its obligations to the Company. Additionally, none of the Company’s derivative instruments contain credit-risk-related contingent features. However, the Company has not incurred any credit-related losses associated with derivative activities and believes that its counterparties will continue to be able to meet their obligations under these transactions.
On June 27, 2011, GMX management made a decision to temporarily suspend our Haynesville/Bossier ("H/B") horizontal ("Hz") drilling program. This decision was made to focus our efforts and resources to the drilling of oil in the newly acquired acreage. As a result of this decision, our projected future production hedged with various counterparties was less than the production that was contractually hedged. Therefore, the production amounts in certain hedging contracts no longer qualified for hedge accounting and the accumulated changes in fair value of $5.1 million were reclassed from other comprehensive income into earnings for the six months ended June 30, 2011.

14

The following is a summary of the asset and liability fair values of our derivative contracts:
 
 
 
Asset Fair Value
 
Liability Fair Value
 
Net Derivative Fair Value
  
Balance Sheet Location
 
June 30, 2011
 
December 31, 2010
 
June 30, 2011
 
December 31, 2010
 
June 30, 2011
 
December 31, 2010
 
 
 
(in thousands)
 
(in thousands)
 
(in thousands)
Derivatives designated as Hedging Instruments under ASC 815
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas
Current derivative asset
 
$
18,500

 
$
23,187

 
$
1,883

 
$
2,963

 
$
16,617

 
$
20,224

Natural gas basis
Current derivative asset
 
—

 
—

 
490

 
566

 
(490
)
 
(566
)
Natural gas
Derivative instruments – non-current asset
 
11,688

 
20,503

 
1,597

 
2,897

 
10,091

 
17,606

Natural gas basis
Derivative instruments – non-current asset
 
—

 
—

 
—

 
122

 
—

 
(122
)
 
 
 
$
30,188

 
$
43,690

 
$
3,970

 
$
6,548

 
$
26,218

 
$
37,142

Derivatives not designated as Hedging Instruments under ASC 815
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas
Current derivative asset
 
$
2,905

 
$
—

 
$
48

 
$
—

 
$
2,857

 
$
—

Crude oil
Current derivative asset
 
—

 
—

 
93

 
172

 
(93
)
 
(172
)
Natural gas
Derivative instruments – non-current asset
 
2,306

 
—

 
52

 
—

 
2,254

 
—

Crude oil
Derivative instruments – non-current asset
 
—

 
—

 
197

 
—

 
(197
)
 
—

 
 
 
$
5,211

 
$
—

 
$
390

 
$
172

 
$
4,821

 
$
(172
)
Net derivative fair value
 
 
 
 
 
 
 
 
 
 
$
31,039

 
$
36,970


15

The following table summarizes the outstanding natural gas and crude oil derivative contracts the Company had in place as of June 30, 2011:
 
Effective Date
 
Maturity Date
 
Notional
Amount
Per
Month
 
Remaining
Notional
Amount as
of June 30,
2011
 
Additional
Put
Options
 
Floor
 
Ceiling
 
Designation under
ASC 815
Natural Gas (MMBtu):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7/1/2011
 
12/31/2012
 
155,833

 
2,805,000

 
 
 
 
 
$
7.00

 
Cash flow hedge
7/1/2011
 
12/31/2011
 
188,783

 
1,132,698

 
 
 
 
 
$
8.00

 
Cash flow hedge
7/1/2011
 
10/31/2011
 
200,000

 
800,000

 
$
5.00

 
$
6.50

 
$
8.30

 
Cash flow hedge
7/1/2011
 
10/31/2011
 
122,286

 
489,143

 
4.00

 
4.50

 
$
5.40

 
Cash flow hedge
11/1/2011
 
3/31/2012
 
200,000

 
1,000,000

 
$
5.50

 
$
7.00

 
 
 
Cash flow hedge
7/1/2011
 
12/31/2012
 
1,034,477

 
18,620,589

 
$
4.00

 
$
6.00

 
 
 
Cash flow hedge
11/1/2011
 
3/31/2012
 
153,580

 
767,902

 
$
4.00

 
$
4.50

 
 
 
Cash flow hedge
11/1/2011
 
3/31/2012
 
180,000

 
900,000

 
 
 
 
 
$
6.25

 
Cash flow hedge
1/1/2013
 
12/31/2013
 
91,250

 
1,095,000

 
$
3.75

 
$
5.25

 
$
6.25

 
Cash flow hedge
1/1/2013
 
12/31/2012
 
304,167

 
3,650,000

 
 
 
$
5.45

 
5.45

 
Cash flow hedge
7/1/2011
 
12/31/2012
 
39,412

 
709,411

 
4.00

 
6.00

 
 
 
Not designated
7/1/2011
 
12/31/2012
 
186,043

 
3,348,780

 
$
4.50

 
$
6.25

 
 
 
Not designated
Crude Oil (Bbls):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7/1/2011
 
12/31/2011
 
3,067

 
18,400

 
 
 
 
 
$
100.00

 
Not designated
4/1/2012
 
12/31/2013
 
1,523

 
36,550

 
 
 
 
 
$
120.00

 
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.
    
As a result of temporarily suspending our H/B Hz drilling program beginning in July 2011, certain hedged natural gas volumes exceeded estimated future production. In order to reduce the amount of hedged volumes, the Company monetized 84,887 Mcf of 2011 hedges and 4.3 Bcfe of 2012 hedges in July 2011. Net of deferred premiums payable related to these volumes, the Company received $2.7 million in net proceeds.
Effects of derivative instruments on the Consolidated Statement of Operations
For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.


16

There were no oil derivatives that qualified for hedges for the three and six months ended June 30, 2011 and 2010. A summary of the effect of the natural gas derivatives qualifying for hedges is as follows:
Description
 
 
Natural Gas  Derivatives
Qualifying as Hedges
 
 
Three Months Ended
June 30,
Location of
Amounts
 
2011
 
2010
 
 
 
(in thousands)
Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion)
OCI
 
(232
)
 
359

Amount of Gain Reclassified from Accumulated OCI into Income (Effective Portion)
Oil and Gas
Sales
 
3,991

 
7,324

Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Oil and Gas
Sales
 
315

 
(1,786
)

 
Description
 
 
Natural Gas  Derivatives
Qualifying as Hedges
 
 
Six Months Ended
June 30,
Location of
Amounts
 
2011
 
2010
 
 
 
(in thousands)
Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion)
OCI
 
5

 
18,567

Amount of Gain Reclassified from Accumulated OCI into Income (Effective Portion)
Oil and Gas
Sales
 
8,436

 
10,964

Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Oil and Gas
Sales
 
722

 
(1,257
)
Assuming that the market prices of oil and natural gas futures as of June 30, 2011 remain unchanged, the Company would expect to transfer a gain of approximately $9.7 million from accumulated other comprehensive income to earnings during the next 12 months. The actual reclassification into earnings will be based on market prices at the contract settlement date.
For derivative instruments that do not qualify as hedges pursuant to ASC 815, changes in the fair value of these derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are recognized in current earnings. A summary of the effect of the derivatives not qualifying for hedges is as follows:
 
 
Location of Gain (Loss) Recognized in
Income on Derivative
 
Amount of Gain (Loss) Recognized in
Income on Derivative
 
 
 
Three Months Ended
June 30,
 
 
 
2011
 
2010
 
 
 
(in thousands)
Realized
 
 
 
 
 
Crude oil
Oil and gas sales
 
$
(44
)
 
$
—

Unrealized
 
 
 
 
 
Natural gas
Unrealized gain or (loss)on derivatives
 
5,110

 
—

Crude oil
Unrealized gain or (loss)on derivatives
 
327

 
107

 
 
 
$
5,393

 
$
107


17

 
Location of Gain (Loss) Recognized in
Income on Derivative
 
Amount of Gain (Loss) Recognized in
Income on Derivative
 
 
 
Six Months Ended
June 30,
 
 
 
2011
 
2010
 
 
 
(in thousands)
Realized
 
 
 
 
 
Natural gas
Oil and gas sales
 
$
—

 
$
23

Crude oil
Oil and gas sales
 
(44
)
 
—

 
 
 
(44
)
 
23

Unrealized
 
 
 
 
 
Natural gas
Unrealized gain or (loss)on derivatives
 
5,110

 
(221
)
Crude oil
Unrealized gain or (loss)on derivatives
 
(118
)
 
107

 
 
 
$
4,948

 
$
(91
)
The valuation of our derivative instruments are based on industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instrument. The Company categorizes these measurements as Level 2. The following table sets forth by level within the fair value hierarchy our derivative instruments, which are our only financial assets and liabilities that were accounted for at fair value on a recurring basis, as of June 30, 2011 and December 31, 2010:
 
As of June 30, 2011
 
As of December 31, 2010
 
Quoted
Prices  in
Active
Markets
(Level  1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Quoted
Prices  in
Active
Markets
(Level  1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
(in thousands)
Financial assets:
 
 
 
 
 
 
 
 
 
 
 
Natural gas derivative instruments
$
—

 
$
31,329

 
$
—

 
$
—

 
$
37,142

 
$
—

Crude oil derivative instruments
$
—

 
$
(290
)
 
$
—

 
$
—

 
$
(172
)
 
$
—



18

NOTE D – STOCK COMPENSATION PLANS
We recognized $1.2 million and $1.1 million of stock compensation expense for the three months ended June 30, 2011 and 2010, respectively and $2.4 million and $3.5 million for the six months ended June 30, 2011 and 2010, respectively. These non-cash expenses are reflected as a component of the Company’s general and administrative expense. To the extent amortization of compensation costs relates to employees directly involved in exploration and development activities, such amounts are capitalized to oil and natural gas properties. Stock based compensation capitalized as part of oil and natural gas properties was $0.1 million and $0.1 million for the three months ended June 30, 2011 and 2010, respectively, and $0.3 million and $0.7 million for the six months ended June 30, 2011 and 2010, respectively.
Restricted Stock
A summary of the status of our unvested shares of restricted stock and the changes for the year ended December 31, 2010 and the six months ended June 30, 2011 is presented below:
 
 
Number of
unvested
restricted shares
 
Weighted
average  grant-
date fair value
per share
Unvested shares as of December 31, 2009
580,530

 
$
22.35

Granted
359,385

 
$
6.34

Vested
(220,016
)
 
$
24.21

Forfeited
(27,903
)
 
$
23.11

Unvested shares as of December 31, 2010
691,996

 
$
13.47

Granted
12,618

 
$
5.55

Vested
(144,680
)
 
$
22.93

Forfeited
(1,683
)
 
$
21.56

Unvested shares as of June 30, 2011
558,251

 
$
10.82

As of June 30, 2011, there was $5.2 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 2.17 years.

NOTE E – CAPITAL STOCK
Share Lending Arrangement
In February 2008, in connection with the offer and sale of the 5.00% convertible notes, we entered into a share lending agreement (the “Share Lending Agreement”). Under this agreement, we loaned to the share borrower up to the maximum number of shares of our common stock underlying the 5.00% convertible notes. As of June 30, 2011, 2,640,000 shares of our common stock were subject to outstanding loans to the share borrower under the Share Lending Agreement.
Sale/Issuance of Common and Preferred Stock
In February 2011, we completed an offering of 21,075,000 shares of our common stock at a price of $4.75 per share. The net proceeds to the Company were $93.6 million after underwriters' discounts and commissions and expenses of the offering payable by the Company. In March 2011, the underwriters exercised the over-allotment option granted in connection with the February 2011 offering and purchased an additional 1,098,518 shares of common stock, which increased the net proceeds to the Company by $4.9 million after underwriters' discounts and commissions and expenses of the offering payable by the Company. The Company used the net proceeds, together with proceeds from a concurrent private placement of the 11.375% Senior Notes, to (i) fund an offer to purchase up to $50.0 million of its 5.00% convertible notes, (ii) repay the then outstanding balance under its revolving bank credit facility and (iii) fund the cash portion of the purchase price of the acquisitions described in Note A. The Company intends to use the remaining net proceeds to fund its exploration and development program and for other general corporate purposes.
In February 2011, the Company issued 2,268,971 common shares in connection with a Bakken acquisition described in Note A. In April 2011, the Company issued an additional 3,542,091 shares of its common stock in connection with another set of Bakken acquisitions also described in Note A.
During the six months ended June 30, 2011, the Company received $25.8 million related to the issuance of 1,135,565 shares of its 9.25% Series B Cumulative Preferred Stock in ongoing at-the-market sales by the Company.

19


NOTE F – INCOME TAXES
We recorded tax (provisions) benefits of $(1.4) million and $(2.4) million for the three months ended June 30, 2011 and 2010, respectively, and $(2.9) million and $3.4 million for the six months ended June 30, 2011 and 2010, respectively, due to changes in the valuation allowance on deferred tax assets. The valuation allowance was adjusted due to increases or decreases in offsetting deferred tax liabilities, primarily as a result of unrealized gains or losses on derivative instruments that qualify for hedge accounting. In determining the carrying value of a deferred tax asset, accounting standards provide for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. As the Company has incurred net operating losses in prior years, relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are insufficient to overcome a history of such losses. In 2008, the Company reduced the carrying value of its net deferred tax asset to zero and maintained that position as of June 30, 2011 and December 31, 2010. The valuation allowance has no impact on our net operating loss (“NOL”) position for tax purposes, and if the Company generates taxable income in future periods, the Company will be able to use its NOLs to offset taxes due at that time. The Company will continue to assess the valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.

NOTE G – COMMITMENTS AND CONTINGENCIES
Litigation
A putative class action lawsuit was filed by the Northumberland County Retirement System and Oklahoma Law Enforcement Retirement System 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, respectively, in late April 2011. The complaint alleges that the registration statement and the prospectus for the offering contained material misstatements and omissions and seek 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. The federal court stayed all further proceedings in this case until after it decides whether to remand the case to state court. If the case remains in federal court, plaintiffs are expected to seek to be appointed lead plaintiff under the Private Securities Litigation Reform Act and to file an amended complaint thereafter. 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.
The Company is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to the Company and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, the Company’s estimates of the outcomes of such matters, and its experience in contesting, litigating, and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to the Company’s financial position or results of operations after consideration of recorded accruals.
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.


20

NOTE H – SUBSEQUENT EVENTS
On August 2, 2011, we entered into an amendment to our revolving bank credit facility to amend the EBITDA to interest expense ratio as defined in the credit agreement to be greater than or equal to 2.00 to 1.00 for the period between July 1, 2011 and December 31, 2011. Beginning January 1, 2012, the required EBITDA to interest expense ratio will return to be greater than or equal to 2.50 to 1.00. During any period between July 1, 2011 and December 31, 2011 in which the Company's EBITDA to interest expense ratio is below 2.50 to 1.00, the applicable LIBO rate margin and applicable prime rate margin will increase by 1.50%. This amendment also increases the unused facility fee by 0.5% to 1.0% per annum when the Company's EBITDA to interest expense ratio is less than 2.50 to 1.00 (or as otherwise provided in the credit facility). The Company paid a fee equal to 1% of the borrowing base in connection with this amendment.

As a result of temporarily suspending our H/B Hz drilling program beginning in July 2011, certain hedged natural gas volumes exceeded estimated future production. In order to reduce the amount of hedged volumes, the Company monetized 84,887 Mcf of 2011 hedges and 4.3 Bcfe of 2012 hedges in July 2011. Net of deferred premiums payable related to these volumes, the Company received $2.7 million in proceeds.



ITEM 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operation.
The following information should be read in conjunction with our unaudited consolidated financial statements and the condensed notes thereto included in this quarterly report on Form 10-Q. The following information and such unaudited consolidated financial statements should also be read in conjunction with the financial statements and related notes thereto, together with our discussion and analysis of our financial position and results of operations, included in our annual report on Form 10-K for the year ended December 31, 2010 (the “2010 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 2010 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 & Sanish-Three Forks and the DJ Basin (Wyoming), targeting the Niobrara Formation. Both plays are estimated to be 90% oil. Our natural gas resources are located in the East Texas Basin, in the Haynesville/Bossier gas shale and the Cotton Valley Sand Formation, where the majority 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 contain nearly 600 undrilled, 9,500' lateral length locations, 43 potential operated 1280-acre units and 172 operated locations, with between 45% and 100% working interest. The Niobrara properties contain 584 undrilled, 4,000' lateral length locations, including 94 potential operated 640-acre units and 376 operated locations, with an average working interest of 51%. The Haynesville/Bossier and the Cotton Valley Sand locations include 253 net Haynesville/Bossier horizontal locations, and 108 net Cotton Valley Sand horizontal locations. The Company believes multiple basins and both oil and natural gas resource choices provide us with flexibility to allocate capital to achieve the highest risk adjusted rate of return on our portfolio.
The first half of 2011 was transformational for the Company with our entry into oil resource plays in the Bakken and Niobrara. We funded acquisitions through capital markets transactions that were successfully completed in early February 2011, including $105 million in an offering of common stock and an offering of $200 million aggregate principal amount of our 11.375% Senior Notes due 2019 (the "11.375% senior notes"). We used $50 million of the proceeds to tender for a portion of our 5.00% convertible senior notes due 2013 (the "5.00% convertible notes"), reducing the aggregate principal amount of that issue to $72.8 million. These capital market transactions allowed us to purchase significant positions in one of the top oil plays in the U.S. (the Bakken) and in a top emerging oil play in the U.S. (the Niobrara), realign our balance sheet and move 80% of our debt past the maturity date of our bank revolver. We also intend to continue acreage acquisitions and to convert our unproved reserves to proved reserves, while maintaining balanced prudent financial management.

21

On July 7, 2011, we spud the first Company-operated Bakken well commencing our multi-year multi-rig drilling program in these properties during the second half of 2011. We may selectively acquire additional acreage in these project areas in the normal course of business.
We believe our current focus on increasing oil production is key to our ability to add shareholder value to the Company. We are focused on accelerating our operational start up in North Dakota, where we now have 600 undrilled 9,500' lateral locations. We are drilling our first operated horizontal Three Forks well, the Wock 21-2-1H, with 100% working interest. The Company has elected to participate in two non-operated wells targeting both the Middle Bakken and Three Forks zones. The working interests in these non-operated wells are 2% and 25%. The Company anticipates participating in six additional non-operated wells in 2011 with an average working interest of 8.4%. The Company has its second well permit for the Frank 31-4-1H, Stark County, and is submitting applications for permits for an additional 14 wells in 14 units in Stark, McKenzie and Billings Counties. Our acreage purchases provide us at least 43 potential operated 1,280-acre units creating 172 undrilled Bakken and Three Forks locations with 45% to 100% working interest. We have approximately 13 other 1,280-acre units where we could operate which provide another 52 undrilled locations as well. In Wyoming, our Niobrara development has begun with two seismic shoots encompassing 135 and 204 square miles. The Company plans to begin operations in the Niobrara in the second half of 2011 with one vertical test well before taking the well horizontal in the first quarter of 2012. Our first shoot is complete and we are evaluating the results. Our second shoot will be completed in the fourth quarter 2011, and we expect to begin drilling test wells in this area subsequent to seismic completion. Our Niobrara acreage position has approximately 146 640-acre units. We currently expect to operate up to 81% of our 584 undrilled 4,000' lateral locations. We plan to commit almost all of our total capital expenditures beginning in the second half of 2011 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.
In May 2011, we increased our Williston Basin position with multiple transactions totaling 11,449 net acres. The first of two significant transactions was a purchase and sale agreement for 9,608 net acres at an average cost of $2,500 per acre, from a private seller, located in Billings and Stark Counties, North Dakota. The second transaction was for 1,684 net acres from the State of North Dakota at an average cost of $2,211 per acre. Approximately 960 net acres are located in McKenzie County and 724 net acres are located in Billings County. The remaining 157 net acres were acquired through the leasing of several fee mineral rights. These acquisitions bring our total Williston Basin net acres 35,524. We hold Williston Basin leases in approximately 150 1,280-acre units and expect to be the operator in approximately 43 of those units, providing a minimum of 172 operated locations. The Company expects that the average working interest in our operated Williston Basin locations will range from approximately 45% to 100%, with the first three operated wells having an 80% to 100% working interest. We have 13 additional possible operated units in North Dakota that could provide another 52 locations.
We intend to use our Haynesville/Bossier horizontal drilling and on-staff technical experience to economically develop our newly acquired Bakken and Niobrara acreage. Our horizontal gas shale team has drilled and completed 38 Haynesville/Bossier horizontal wells to date, including long laterals of nearly 7,000 feet. We have opened a Denver office and assembled a technical staff of additional land, engineers and geologists with significant Rocky Mountain experience.
All of our Haynesville/Bossier acreage is held by production, which enables us to shift capital to higher economic return basins without risking the loss of core acreage. We have temporarily suspended drilling new Haynesville /Bossier horizontal wells as of July 2011 and are focusing our capital to accelerating the development of our oil acreage. We expect to continue to explore for additional oil opportunities within our core East Texas acreage. We anticipate reactivating our drilling program in July 2013 in the Haynesville/Bossier Shale in order to continue development of our natural gas reserves in our historic primary development area in East Texas. We estimate that our approximate 25,224 net acres in our primary development area of the Haynesville/Bossier Shale includes as many as 253 net potential undrilled locations based on 80-acre spacing.
We plan to continue to use hedging to mitigate commodity price risks for our oil and gas production. As of June 30, 2011, the Company had hedged approximately 7.8 million MMBtu, 16.7 million MMBtu and 4.7 million MMBtu of natural gas at a weighted average floor price of $6.13, $6.08 and $5.40 per MMbtu for 2011, 2012 and 2013, respectively.
The table below summarizes information concerning our operating activities in the three and six months ended June 30, 2011 compared to the three and six months ended June 30, 2010.

22

Summary Operating Data
 

Three Months Ended

Six Months Ended
 
June 30,

June 30,
 
2011

2010

2011

2010
Production:







Oil (MBbls)
24


24


46


46

Natural gas (MMcf)
5,852


3,592


11,367


6,085

Natural gas liquids (Mgals)
3,678


4,005


6,442


8,023

Gas equivalent production (MMcfe)
6,524


4,308


12,563


7,507

Average daily (MMcfe)
71.7


47.3


69.4


41.5

Average Sales Price:







Oil (per Bbl)







Sales price
$
100.04


$
75.98


$
96.41


$
75.73

Effect of derivatives, excluding gain or loss from ineffectiveness of derivatives
(1.79
)

—


(0.95
)

—

Total
$
98.25


$
75.98


$
95.46


$
75.73

Natural gas liquids (per gallon)







Sales price
$
0.95


$
0.78


$
0.91


$
0.86

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


—


—


—

Total
$
0.95


$
0.78


$
0.91


$
0.86

Natural gas (per Mcf)







Sales price
$
3.87


$
3.55


$
3.77


$
4.01

Effect of derivatives, excluding gain or loss from ineffectiveness of derivatives
0.68


2.04


0.74


1.80

Total
$
4.55


$
5.59


$
4.51


$
5.81

Average sales price (per Mcfe)
$
5.04


$
5.39


$
4.95


$
5.93

Operating and Overhead Costs (per Mcfe):







Lease operating expenses
$
0.43


$
0.52


$
0.46


$
0.71

Production and severance taxes
0.03


0.07


0.04


0.14

General and administrative
1.17


1.44


1.17


1.79

Other (per Mcfe):







Depreciation, depletion and amortization—oil and natural gas properties
$
1.81


$
1.75


$
1.84


$
1.70



23


Results of Operations for the Three Months Ended June 30, 2011 Compared to the Three Months Ended June 30, 2010
Oil and Natural Gas Sales. Oil and natural gas sales during the three months ended June 30, 2011 increased 42% to $32.9 million compared to $23.2 million in the second quarter of 2010. The increase in oil and natural gas sales was due to an 51.4% increase in production on a Bcfe-basis, a 29.3% increase in oil prices and a 21.8% increase in the average realized price in natural gas liquids (“NGLs”), offset by a 18.6% decrease in the average realized price of natural gas, excluding ineffectiveness of hedging activities. The average price per barrel of oil, per gallon of natural gas liquids NGLs and Mcf of natural gas received (exclusive of ineffectiveness from derivatives) in the three months ended June 30, 2011 was $98.25, $0.95 and $4.55, respectively, compared to $75.98, $0.78 and $5.59, respectively, in the three months ended June 30, 2010. Our realized sales price for natural gas, excluding the effect of hedges of $0.68 and $2.04, for the three months ended June 30, 2011 and 2010, respectively, was approximately 90% and 86% of the average NYMEX closing contract price for the respective periods. In the second quarter of 2011 and 2010, the conversion of natural gas to NGLs produced an upgrade of approximately $0.42 per Mcf and $0.47 per Mcf, respectively, for every Mcf of natural gas produced. This upgrade in value was previously included in the realized price of our natural gas sales. Ineffectiveness of derivative gains (losses) recognized in oil and gas sales of $0.3 million and $(1.8) million for the three months ended June 30, 2011 and 2010, respectively, is the result of a difference in the fair value of our cash flow hedges and the fair value of the projected cash flows of a hypothetical derivative based on our expected sales point.
Natural gas production for the three months ended June 30, 2011 increased to 5,852 MMcf compared to 3,592 MMcf for the three months ended June 30, 2010, an increase of 62.9%. The increase in natural gas production resulted from production related to 37.1 net producing Haynesville/Bossier ("H/B") horizontal wells that were on-line during the second quarter of 2011 compared to 19.5 net producing H/B horizontal wells online during the second quarter of 2010. During the second quarter of 2011, we brought on-line three H/B horizontal wells and production from all H/B horizontal wells, including the three H/B horizontal wells brought on-line in the second quarter 2011, which accounted for 78% of total production for the three months ended June 30, 2011 compared to 61% in the same period in 2010. Oil production for the three months ended June 30, 2011 remained the same as of the three months ended June 30, 2010 at 24 MBbls. During the first quarter of 2011, we began to separate and report the production and revenue from our NGLs, compared to prior periods in which we had included NGL production and revenues in our natural gas production and sales amounts. NGL production for the three months ended June 30, 2011 decreased to 3,678 Mgals compared to 4,005 Mgals for the three months ended June 30, 2010, a decrease of 8.1%. This decrease was due to a decline in production in our non-Haynesville production, which has a higher NGL content compared to our H/B horizontal wells.
For the three months ended June 30, 2011, as a result of hedging activities but excluding derivative ineffectiveness, we recognized an increase in natural gas sales of $3.9 million compared to an increase in natural gas sales of $7.3 million in the second quarter of 2010. In the second quarter of 2011, hedging, excluding ineffectiveness, increased the average natural gas sales price by $0.68 per Mcf compared to an increase in natural gas sales price of $2.04 per Mcf in the second quarter of 2010. The effect of our derivative contracts decreased oil sales by $44,000 and decreased the average oil sales price $1.79 per Bbl for the three months ended June 30, 2011 compared to no effect in the same period in 2010.
Lease Operations. Lease operations expense increased $0.6 million, or 26%, for the three months ended June 30, 2011 to $2.8 million, compared to $2.2 million for the three months ended June 30, 2010. Lease operations expense on an equivalent unit of production basis decreased $0.09 per Mcfe in the three months ended June 30, 2011 to $0.43 per Mcfe, compared to $0.52 per Mcfe for the three months ended June 30, 2010. The decrease in lease operations expense on an equivalent unit basis resulted from an increase in H/B horizontal well production and cost control measures implemented by us during 2010, which lowered overall lease operating expense. With little to no incremental increase in lease operations cost from a Cotton Valley vertical well, the significantly larger amount of production from a H/B horizontal well will result in lower per unit lease operations costs. The overall increase in lease operations expense is primarily related to higher gathering costs plus an increase in salt water disposal expense related to the increase in production in the three months ended June 30, 2011 compared to the three months ended June 30, 2010.
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 47% to $0.2 million in the three months ended June 30, 2011 compared to $0.3 million in the three months ended June 30, 2010.

24

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $4.6 million, or 52%, to $13.3 million in the three months ended June 30, 2011 compared to $8.7 million for the three months ended June 30, 2010. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.81 per Mcfe in the three months ended June 30, 2011 compared to $1.75 per Mcfe in the three months ended June 30, 2010. This increase in the rate per Mcfe is due to the percentage increase in oil and gas properties subject to amortization exceeding the percentage growth in reserves for the three months ended June 30, 2011.
        Impairment of oil and natural gas properties and assets held for sale. For the $16.9 million impairment charge recorded in the second quarter of 2011, $11.5 million was related to the impairment of oil and gas properties subject to the full cost ceiling test and $5.4 million was related to a change in value 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 currently represents 90% of the Company’s total production, and as a result, a decrease in natural gas prices can significantly impact the Company’s ceiling test. During the second quarter of 2011, the 12-month average of the first day of the month natural gas price increased 3% from $4.10 per MMbtu at March 31, 2011 to $4.21 per MMbtu at June 30, 2011. Even though the 12-month average of the first day of the month natural gas price increased during the second quarter of 2011, the Company recorded impairment expense of $11.5 million related to oil and gas properties. Of the $11.5 million related to oil and gas properties, $3.0 million resulted from the net book value of oil and gas properties exceeding the net present value of future net revenues, $3.4 million related to the decrease in net present value of the cash flow hedges used in the full cost ceiling test and $5.1 million related to the de-designation of cash flow hedges that could no longer be considered in the full cost ceiling test. The remaining $5.4 million of the $16.9 million impairment charge was related to additional impairment on the Company's three drilling rigs, currently classified as assets held for sale, and was based on a change in fair value of the rigs used to calculate the impairment which reflects the sales price of one of the rigs sold in July 2011.
General and Administrative Expense. General and administrative expense for the three months ended June 30, 2011 was $7.6 million compared to $6.2 million for the three months ended June 30, 2010, an increase of $1.4 million, or 22%. General and administrative expense per equivalent unit of production was $1.17 per Mcfe for the second quarter of 2011 compared to $1.44 per Mcfe for the comparable period in 2010. The increase in general and administrative expense for the three months ended June 30, 2011 compared to the three months ended June 30, 2010 was primarily due to an increase in salaries, wages and related payroll taxes as a result of an increase in employees associated with the Company's oil-related acreage expansion. General and administrative expenses include $1.2 million and $1.1 million of non-cash compensation expense as of the three months ended June 30, 2011 and 2010, respectively. Non-cash compensation represented 16% and 18% of total general and administrative expenses, for the three months ended June 30, 2011 and 2010, respectively. General and administrative expense has not historically varied in direct proportion to oil and natural gas production because certain types of general and administrative expenses are non-recurring or fixed in nature.
Interest. Interest expense for the three months ended June 30, 2011 was $7.8 million compared to $4.7 million for the same period in 2010. For the three months ended June 30, 2011 and 2010, interest expense includes non-cash interest expense of $1.4 million and $1.7 million, respectively, related to the accounting for convertible bonds, our share lending agreement and deferred premiums on derivative instruments. Cash interest expense for the three months ended June 30, 2011 and 2010 was $7.7 million and $2.9 million, respectively, of which $2.0 million and $0.6 million, respectively, was capitalized to properties not subject to amortization on the consolidated balance sheets. The increase in cash interest expense of $4.8 million was mainly due to the Company’s issuance and sale of $200 million aggregate principal amount of 11.375% senior notes in February 2011.
Income Taxes. Income tax for the three months ended June 30, 2011 was a provision of $1.4 million as compared to a provision of $2.4 million in the same period in 2010. The income tax expense recognized in the three months ended June 30, 2011 and 2010, 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 unrealized gains on derivative contracts designated as hedges where the mark-to-market change on the hedges, net of deferred taxes is recorded to other comprehensive income.
Net income to non-controlling interest. Net income to non-controlling interest increased to $1.7 million for the three months ended June 30, 2011 compared to $0.6 million for the three months ended June 30, 2010. The increase is due to an increase in the gathering fees earned by our majority-owned subsidiary in which the outside non-controlling interest member is currently allocated 80% of the distributions. The gathering fees earned by the subsidiary increased as a result of an increase in production from the H/B horizontal wells that were completed and brought online.


25

Results of Operations for the Six Months Ended June 30, 2011 Compared to the Six Months Ended June 30, 2010
Oil and Natural Gas Sales. Oil and natural gas sales during the six months ended June 30, 2011 increased 40% to $62.2 million compared to $44.5 million in the six months ended June 30, 2010. Ineffectiveness of derivative gains (losses) recognized in oil and gas sales of $0.7 million and $(1.3) million for the six months ended June 30, 2011 and 2010, respectively, is the result of a difference in the fair value of our cash flow hedges and the fair value of the projected cash flows of a hypothetical derivative based on our expected sales point. The increase in oil and natural gas sales was due to a 67.4% increase in production on a Bcfe-basis, a 26.1% increase in oil prices, a 5.8% increase in the average realized price of NGLs, offset by an 22.4% decrease in the average realized price of natural gas, excluding ineffectiveness of hedging activities. The average price per barrel of oil, per gallon of natural gas liquids NGLs and Mcf of natural gas received (excluding ineffectiveness from derivatives) in the six months ended June 30, 2011 was $95.46, $0.91 and $4.51, respectively, compared to $75.73, $0.86 and $5.81, respectively, in the six months ended June 30, 2010. Our realized sales price for natural gas, excluding the effect of hedges of $0.74 and $1.80, for the six months ended June 30, 2011 and 2010, respectively, was approximately 89% and 86% of the average NYMEX closing contract price for the respective periods. In the first six months of 2011 and 2010, the conversion of natural gas to NGLs produced an upgrade of approximately $0.35 per Mcf and $0.65 per Mcf, respectively, for every Mcf of natural gas produced. This upgrade in value was previously included in the realized price of our natural gas sales.
Natural gas production for the six months ended June 30, 2011 increased to 11,367 MMcf compared to 6,085 MMcf for the six months ended June 30, 2010, an increase of 87%. The increase in natural gas production resulted from production related to 37.1 net producing H/B horizontal wells that were on-line during the first six months of 2011 compared to 19.5 net producing H/B horizontal wells online during the first six months of 2010. During the six months ended June 30, 2011, we brought on-line seven H/B horizontal wells and production from H/B horizontal wells, which accounted for 77% of total production for the six months ended June 30, 2011 compared to 55% in the same period in 2010. Production of oil for the six months ended June 30, 2011 remained the same as the six months ended June 30, 2010 at 46 MBbls. During the first quarter of 2011, we began to separate and report the production and revenue from our NGLs, compared to prior periods in which we had included NGL production and revenues in our natural gas production and sales amounts. NGL production for the six months ended June 30, 2011 decreased to 6,442 Mgals compared to 8,023 Mgals for the six months ended June 30, 2010, a decrease of 20%. This decrease was due to a decline in production in our non-Haynesville wells, which have a higher NGL content compared to our H/B horizontal wells.
For the six months ended June 30, 2011, as a result of hedging activities but excluding derivative ineffectiveness, we recognized an increase in natural gas sales of $8.4 million compared to an increase in natural gas sales of $10.9 million in the six months ended June 30, 2010. In the six months ended June 30, 2011, hedging, excluding ineffectiveness, increased the average natural gas sales price by $0.74 per Mcf compared to an increase in natural gas sales price of $1.80 per Mcf in the same period of 2010. The effect of our derivative contracts on oil decreased the average oil sales price $0.95 per Bbl for the six months ended June 30, 2011 compared to no effect in the same period in 2010.
Lease Operations. Lease operations expense increased $0.3 million, or 7%, for the six months ended June 30, 2011 to $5.7 million, compared to $5.4 million for the six months ended June 30, 2010. Lease operations expense on an equivalent unit of production basis decreased $0.25 per Mcfe in the six months ended June 30, 2011 to $0.46 per Mcfe, compared to $0.71 per Mcfe for the six months ended June 30, 2010. The decrease in lease operations expense on an equivalent unit basis resulted from an increase in H/B horizontal well production and cost control measures implemented by us during 2010 which lowered overall lease operating expense. With little to no incremental increase in lease operations cost from a Cotton Valley vertical well, the significantly larger amount of production from a H/B horizontal well will result in lower per unit lease operations costs. The overall increase in lease operations expense is primarily related to higher gathering costs plus an increase in salt water disposal expense related to the increase in production in the six months ended June 30, 2011 compared to the six months ended June 30, 2010.
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 47% to $0.5 million in the six months ended June 30, 2011 compared to $1.0 million in the six months ended June 30, 2010.

26

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $11.0 million, or 73%, to $26.1 million in the six months ended June 30, 2011 compared to $15.1 million for the six months ended June 30, 2010. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.84 per Mcfe in the six months ended June 30, 2011 compared to $1.70 per Mcfe in the six months ended June 30, 2010. This increase in the rate per Mcfe is due to the percentage increase in oil and gas properties subject to amortization exceeding the percentage growth in reserves for the six months ended June 30, 2011.
        Impairment of oil and natural gas properties. For the $65.2 million impairment charge recorded in the first six months of 2011, $59.6 million of the charge was related to the impairment of oil and gas properties subject to the full cost ceiling test and $5.6 million was related to a change in value 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 represents 90% of the Company’s total production, and as a result, a decrease in natural gas prices can significantly impact the Company’s ceiling test. During the six months ended June 30, 2011, the 12-month average of the first day of the month natural gas price decreased 4% from $4.38 per MMbtu at December 31, 2011 to $4.21 per MMbtu at June 30, 2011. Of the $59.6 million related to the impairment of oil and gas properties, $14.5 million related to the acquisition cost of East Texas and north Louisiana undeveloped acreage outside of our primary development area being subject to the full cost method ceiling test and was based on the Company’s decision during the first quarter of 2011 not to develop the acreage, totaling 9,750 net acres, before the expiration of the related leases in 2011. The Company’s decision not to develop the acreage was based on analysis completed in the first quarter of 2011, of the opportunities including off-set wells, anticipated future gas prices, infrastructure costs, the Company’s liquidity position and focus on exploration and development of the newly acquired acreage in Bakken and Niobrara areas. Previously disclosed potential undrilled locations associated with our H/B acreage has excluded consideration of this acreage and therefore does not have an impact to our undrilled location opportunities to continue the Company’s growth in our H/B production. Additionally, there are no proved reserves recorded by the Company associated with these acres. We have determined the cost of these undeveloped leases should be transferred to properties being amortized and subject to our full cost ceiling test. Of the remaining $45.1 million related to the impairment of oil and gas properties, $34.0 million resulted from the net book value of oil and gas properties exceeding the net present value of future net revenues. $6.0 million related to the decrease in net present value of the cash flow hedges used in the full cost ceiling test and $5.1 million due to the de-designation of cash flow hedges that could no longer be considered in the full cost ceiling test. Approximately $5.4 million of the $65.2 million impairment charge was related to additional impairment on the Company's three drilling rigs, currently classified as assets held for sale, and was based on a change in fair value of the rigs used to calculate the impairment which reflects the sales price of one of the rigs sold in July 2011.
General and Administrative Expense. General and administrative expense for the six months ended June 30, 2011 was $14.7 million compared to $13.4 million for the six months ended June 30, 2010, an increase of $1.3 million, or 10%. General and administrative expense per equivalent unit of production was $1.17 per Mcfe for the six months ended June 30, 2011 compared to $1.79 per Mcfe for the comparable period in 2010. The overall increase in general and administrative expense for the six months ended June 30, 2011 compared to the six months ended June 30, 2011 was primarily due to an increase in salaries, wages and related payroll taxes as a result of an increase in employees associated with the Company's oil-related acreage expansion. General and administrative expenses include $2.2 million and $3.5 million of non-cash compensation expense as of the six months ended June 30, 2011 and 2010, respectively. Non-cash compensation represented 15% and 26% of total general and administrative expenses, excluding severance costs for the six months ended June 30, 2011 and 2010, respectively. General and administrative expense has not historically varied in direct proportion to oil and natural gas production because certain types of general and administrative expenses are non-recurring or fixed in nature.
Interest. Interest expense for the six months ended June 30, 2011 was $15.9 million compared to $8.9 million for the same period in 2010. For the six months ended June 30, 2011 and 2010, interest expense includes non-cash interest expense of $2.9 million and $3.7 million, respectively, related to the accounting for convertible bonds, our share lending agreement and deferred premiums on derivative instruments. Cash interest expense for the six months ended June 30, 2011 and 2010 was $14.2 million and $5.5 million, respectively, of which $3.0 million and $1.1 million, respectively was capitalized to properties not subject to amortization on the consolidated balance sheets. The increase in cash interest expense of $8.8 million was mainly due to the Company’s issuance and sale of $200 million aggregate principal amount of 11.375% senior notes in February 2011.
Income Taxes. Income tax for the six months ended June 30, 2011 was a provision of $2.9 million as compared to a benefit of $3.4 million in the same period in 2010. The income tax expense and benefit recognized in the six months ended June 30, 2011 and 2010, respectively, were a result of a change in the valuation allowance on net deferred tax assets caused by a change in deferred tax liabilities primarily related to unrealized gains on derivative contracts designated as hedges where the mark-to-market change on the hedges, net of deferred taxes is recorded to other comprehensive income.

27

Net income to noncontrolling interest. Net income to noncontrolling interest increased to $3.2 million for the six months ended June 30, 2011 compared to $0.9 million for the six months ended June 30, 2010. The increase is due to an increase in the gathering fees earned by our majority-owned subsidiary in which the outside noncontrolling interest member is currently allocated 80% of the distributions. The gathering fees earned by the subsidiary increased as a result of an increase in production from the H/B horizontal wells that were completed and brought online.
Net Income and Net Income Per Share
Net Loss and Net Loss Per Share—Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010. For the three months ended June 30, 2011, we reported a net loss applicable to common shareholders of $15.4 million, and for the three months ended June 30, 2010, we reported a net loss applicable to common shareholders of $3.0 million. Net loss per basic and fully diluted share was $0.28 for the second quarter of 2011 compared to net loss per basic and fully diluted share of $0.11 for the second quarter of 2010.
    
Net Income and Net Income Per Share—Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010. For the six months ended June 30, 2011, we reported a net loss applicable to common shareholders of $69.8 million, and for the six months ended June 30, 2010, we reported net income applicable to common shareholders of $0.8 million. Net loss per basic and fully diluted share was $1.43 for the first six months of 2011 compared to net income per basic and fully diluted share of $0.03 for the first six months of 2010.

Capital Resources and Liquidity
Our business is capital intensive. Our ability to grow our reserve base is dependent upon our ability to obtain outside capital and generate cash flows from operating activities to fund our drilling and capital expenditures. Our cash flows from operating activities are substantially dependent upon crude oil and natural gas prices, and significant decreases in market prices of crude oil or natural gas could result in reductions of cash flow and affect our drilling and capital expenditure plan. To mitigate a portion of our exposure to fluctuations in natural gas prices, we have entered into natural gas swaps, three-way collars and put spreads.
As of June 30, 2011, we had cash and cash equivalents of $4.9 million and our undrawn borrowing base of $60.0 million as of June 30, 2011. Through the period ended June 30, 2011, we have funded our operating expenses and capital expenditures through positive operating cash flows, as well as from $105.3 million raised from the issuance of 22,173,518 shares of our common stock in February 2011, $25.8 million raised from the issuance of 1,135,565 shares of our 9.25% Series B Cumulative Preferred Stock preferred shares and $193.7 million, net of original issue discount, raised from the issuance of our 11.375% senior notes. The outstanding balance of our bank credit facility at the time of the offerings of $110 million was fully repaid, and we completed a $50 million tender offer for a portion of our 5.00% convertible notes. The remaining proceeds from the offerings were used to fund the Niobrara and Bakken acreage acquisitions and will be used for future capital expenditures.
We continually review our drilling and capital expenditure plans and may change the amount we spend based on industry and market conditions and the availability of capital. In the first six months of 2011, our cash outlay for capital expenditures was $192 million, net of additions to oil and gas properties from issuance of common stock for the Bakken and Niobrara acreage acquisitions. Cash expenditures related to the purchase price of Niobrara and Bakken acreage acquisitions totaled $90.8 million for the six months ended June 30, 2011. Additional Bakken-Williston Basin acquisitions were completed in the second quarter of 2011 in which the Company purchased an additional 11,449 net acres in the Williston Basin for a total purchase price of $28 million, bringing our total Williston Basin net acres to 35,524 respectively.
Our revised cash capital expenditure budget for 2011 is $287 million, of which $101 million is the cash portion of acreage acquisitions in the Williston Basin, DJ Basin-Niobrara and East Texas and $186 million is for drilling operations of which we estimate approximately 28% will be spent on oil-related activities. We have elected to temporarily suspend execution of our H/B horizontal program until natural gas prices or lower completed well costs support more economical drilling, which we expect to occur by mid-year 2013. We will complete our eighth and final H/B horizontal well for this calendar year in the third quarter of 2011.
We anticipate funding the $94 million of cash capital expenditures in the second half of 2011 with positive operating cash flow, the unused portion of our revolving bank credit facility, proceeds from sales of assets held for sale and continued at-the-market sales of our 9.25% Series B Cumulative Preferred Stock.

    

28

In order to protect us against the financial impact of a decline in natural gas prices, we have an active hedging program. As of June 30, 2011, we had natural gas hedges in place of 7.8 Bcf for our remaining estimated natural gas production for 2011 at an average hedge floor price of $6.13 per Mcf. In addition, we have 16.7 Bcf and 4.7 Bcf of natural gas hedged in 2012 and 2013, respectively, at average hedge prices of $6.08 and $5.40 per Mcf. As of June 30, 2011, we have also sold put options that would reduce the average hedge floor price if the monthly natural gas contract settlement price is below $4.18 for 2011, $4.12 for 2012 and $3.75 for 2013. If the monthly natural gas contract settlement is below the average sold put price, we will receive the monthly natural gas contract settlement price plus $1.95 in 2011, $1.95 in 2012, and $1.65 in 2013.

As a result of temporarily suspending the H/B horizontal drilling program in July 2011, certain hedged natural gas volumes exceeded estimated future production. In order to reduce the amount of hedged volumes, the Company monetized 84,887 Mcf of 2011 hedges and 4.3 Bcfe of 2012 hedges. Net of deferred premiums payable related to these volumes, the Company received $2.7 million in proceeds.

For further discussion of our derivative instruments, please also read Note C to the notes to unaudited financial statements included in this report.
Cash Flow—Six months Ended June 30, 2011 Compared to Six months Ended June 30, 2010
In the six months ended June 30, 2011 and 2010, we spent $192.3 million and $77.6 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 six months ended June 30, 2011 by cash flow from operations, issuance of additional preferred and common stock and issuance of our 11.375% senior notes. Cash flow provided by operating activities in the six months ended June 30, 2011 was $37.6 million compared to $22.5 million in the six months ended June 30, 2010.
For a discussion of our derivative activity, please also see “Capital Resources and Liquidity,” “Quantitative and Qualitative Disclosures About Market Risk” and Note C to the notes to unaudited financial statements included in this report.
Revolving Bank Credit Facility and Other Debt
Revolving Bank Credit Facility. We have a secured revolving bank credit facility, and on February 2, 2011 we entered into a Fifth Amended and Restated Loan Agreement (the "Restated Loan Agreement"), which matures on January 1, 2013 but can be extended automatically to December, 31, 2013 under certain circumstances. The Restated Loan Agreement provides for a line of credit of up to $100 million (the “commitment”), subject to a borrowing base which is based on a periodic evaluation of our oil and gas reserves (“borrowing base”). The amount of credit available at any one time under the revolving bank credit facility is the lesser of the borrowing base or the amount of the commitment.
As of June 30, 2011, we had no funds drawn on our revolving bank credit facility which has a borrowing base of $60 million. Our next semi-annual redetermination is scheduled to be completed in October 1, 2011. The revolving bank credit facility contains various affirmative and restrictive covenants. These covenants, among other things, prohibit additional indebtedness, sale of assets, mergers and consolidations, dividends and distributions, and changes in management and require the maintenance of various financial ratios. We were in compliance with all financial and nonfinancial covenants under our revolving bank credit facility at June 30, 2011. For further discussion of our revolving bank credit facility, please also read Note B and Note H to the notes to unaudited financial statements included in this report.
Convertible Notes. We issued $125 million of 5.00% convertible notes due 2013 in February 2008 and $86.25 million of 4.50% convertible senior notes due 2015 (“4.50% convertible notes”) in October 2009. These convertible notes are unsecured. On January 28, 2011, the Company announced the commencement of a tender offer for up to $50 million aggregate principal amount of the outstanding 5.00% convertible notes. The tender offer expired March 11, 2011, and the Company retired $50 million aggregate principal amount of the 5.00% convertible notes. We were in compliance with the terms of the 5.00% convertible notes and the 4.50% convertible notes at June 30, 2011. 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. We issued $200 million of 11.375% senior notes in February 2011. We were in compliance with the terms of the 11.375% senior notes at June 30, 2011. 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.

29

Working Capital
At June 30, 2011, we had working capital of $(10.2) million. Including availability under our revolving bank credit facility, our working capital as of June 30, 2011 would have been $49.8 million.
Price Risk Management
See Part I, Item 3 – Quantitative and Qualitative Disclosure about Market Risk.
Critical Accounting Policies
Our critical accounting policies are summarized in our 2010 Form 10-K. There have been no changes in those policies.
Contractual Obligations
Our contractual obligations are summarized in our 2010 Form 10-K.

During the six months ended June 30, 2011, we entered into four new contractual agreements. We entered into a 62-month lease for office space in Denver, Colorado for a total obligation of approximately $0.5 million, as well as a 58-month lease for office space in Oklahoma City, Oklahoma for a total obligation of approximately $1.4 million. In addition, we entered into a 36-month lease commitment for a Company aircraft for a total obligation of $0.9 million. In July 2011, we also entered into a one-year rig lease agreement for $24,500 per day from for a total obligation of approximately $9.0 million.
Recently Issued Accounting Standards
See Note A to our financial statements included in Part I, Item 1 of this quarterly report.
Off-Balance Sheet Arrangements
We do not currently have any off-balance sheet arrangements.
Forward-Looking Statements
All statements made in this document other than purely historical information are “forward looking statements” within the meaning of the federal securities laws. These statements reflect expectations and are based on historical operating trends, proved reserve positions and other currently available information. Forward-looking statements include statements regarding future plans and objectives, future exploration and development expenditures, the number and location of planned wells, the quality of our properties and potential reserve and production levels, and future revenue and cash flow. These statements may be preceded or followed by or otherwise include the words “believes”, “expects”, “anticipates”, “intends”, “continues”, “plans”, “estimates”, “projects”, “guidance” or similar expressions or statements that events “will” “should”, “could”, “might” or “may” occur. Except as otherwise specifically indicated, these statements assume that no significant changes will occur in the operating environment for oil and gas properties and that there will be no material acquisitions or divestitures except as otherwise described.
The forward-looking statements in this report are subject to all the risks and uncertainties which are described in our 2010 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.


30

ITEM 3.
Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We are subject to price fluctuations for natural gas and crude oil. Prices received for natural gas and crude oil sold on the spot market are volatile due to factors beyond our control. Reductions in crude oil and natural gas prices could have a material adverse effect on our financial position, results of operations, capital expenditures and quantities of reserves recoverable on an economic basis. Any reduction in reserves, including reductions due to lower prices, can reduce our borrowing base under our revolving bank credit facility and adversely affect our liquidity and our ability to obtain capital for our acquisition and development activities.
To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into financial price risk management activities with respect to a portion of projected crude oil and natural gas production through financial price commodity swaps, collars and put spreads. Our revolving bank credit facility requires us to maintain a hedging program on mutually acceptable terms whenever the loan amount outstanding exceeds 75% of the borrowing base.
The United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation was signed into law by the President on July, 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure its existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
The following table summarizes the outstanding crude oil and natural gas derivative contracts we had in place as of June 30, 2011:
 
Effective Date
 
Maturity Date
 
Notional
Amount
Per
Month
 
Remaining
Notional
Amount as
of June 30,
2011
 
Additional
Put
Options
 
Floor
 
Ceiling
 
Designation under
ASC 815
Natural Gas (MMBtu):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7/1/2011
 
12/31/2012
 
155,833

 
2,805,000

 
 
 
 
 
$
7.00

 
Cash flow hedge
7/1/2011
 
12/31/2011
 
188,783

 
1,132,698

 
 
 
 
 
$
8.00

 
Cash flow hedge
7/1/2011
 
10/31/2011
 
200,000

 
800,000

 
$
5.00

 
$
6.50

 
$
8.30

 
Cash flow hedge
7/1/2011
 
10/31/2011
 
122,286

 
489,143

 
4.00

 
4.50

 
$
5.40

 
Cash flow hedge
11/1/2011
 
3/31/2012
 
200,000

 
1,000,000

 
$
5.50

 
$
7.00

 
 
 
Cash flow hedge
7/1/2011
 
12/31/2012
 
1,034,477

 
18,620,589

 
$
4.00

 
$
6.00

 
 
 
Cash flow hedge
11/1/2011
 
3/31/2012
 
153,580

 
767,902

 
$
4.00

 
$
4.50

 
 
 
Cash flow hedge
11/1/2011
 
3/31/2012
 
180,000

 
900,000

 
 
 
 
 
$
6.25

 
Cash flow hedge
1/1/2013
 
12/31/2013
 
91,250

 
1,095,000

 
$
3.75

 
$
5.25

 
$
6.25

 
Cash flow hedge
1/1/2013
 
12/31/2012
 
304,167

 
3,650,000

 
 
 
$
5.45

 
5.45

 
Cash flow hedge
7/1/2011
 
12/31/2012
 
39,412

 
709,411

 
4.00

 
6.00

 
 
 
Not designated
7/1/2011
 
12/31/2012
 
186,043

 
3,348,780

 
$
4.50

 
$
6.25

 
 
 
Not designated
Crude Oil (Bbls):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7/1/2011
 
12/31/2011
 
3,067

 
18,400

 
 
 
 
 
$
100.00

 
Not designated
4/1/2012
 
12/31/2013
 
1,523

 
36,550

 
 
 
 
 
$
120.00

 
Not designated

31

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 fair value of our natural gas and oil derivative contracts in effect at June 30, 2011 was $31.0 million, of which $18.9 million is classified as a current asset and $12.1 million is classified as a long-term asset.
Based on the monthly notional amount for natural gas in effect at June 30, 2011, a hypothetical $0.10 increase in natural gas prices would have decreased the fair value from our natural gas swaps and options by $5.0 million, and a $0.10 decrease in natural gas prices would have increased the fair value from our natural gas swaps and option by $4.9 million. Based on the monthly notional amount for crude oil in effect at June 30, 2011, a hypothetical $1.00 increase or decrease in oil prices would have no material impact on the fair value for our crude oil derivative contract.
Interest Rate Risk
As of June 30, 2011, we had no amounts outstanding under our revolving bank credit facility. The revolving bank credit facility matures on January 1, 2013 but can be extended automatically to December 31, 2013 under certain circumstances and is governed by a borrowing base calculation that is redetermined periodically. We have the option to elect interest at either (a) a base rate tied to the greatest of (i) the prime rate as published in The Wall Street Journal plus a margin ranging from 1% to 2% based on the amount of the loan outstanding in relation to the borrowing base, (ii) the federal funds rate plus a margin ranging from 2.50% to 4.00% based on the amount of the loan outstanding in relation to the borrowing base, or (iii) the one-month LIBO rate plus a margin ranging from 2.00% to 3.50% based on the amount of the loan outstanding in relation to the borrowing base (payable monthly), or (b) the LIBO rate plus a margin ranging from 2.00% to 3.50% based on the amount of the loan outstanding in relation to the borrowing base for a period of one, two or three months (payable at the end of such period). As a result, our interest costs fluctuate based on short-term interest rates relating to our revolving bank credit facility if a balance is outstanding. We did not hold any interest rate derivatives during the six months ended 2011 and 2010.
Our $86.25 million of 4.50% convertible notes and $72.75 million of 5.00% convertible notes have fixed interest rates of 4.50% and 5.00%, respectively. Our $200 million of 11.375% senior notes, have a fixed interest rate of 11.375%.

ITEM 4.
Controls and Procedures
Evaluation of disclosure controls and procedures as of June 30, 2011. 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 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.


32

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 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, respectively, in late April 2011. The complaint alleges that the registration statement and the prospectus for the offering contained material misstatements and omissions and seek 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. The federal court stayed all further proceedings in this case until after it decides whether to remand the case to state court. If the case remains in federal court, plaintiffs are expected to seek to be appointed lead plaintiff under the Private Securities Litigation Reform Act and to file an amended complaint thereafter. 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.
We are party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to the Company and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, the Company’s estimates of the outcomes of such matters, and its experience in contesting, litigating, and settling similar financial position or results of operations after consideration of recorded accruals.

ITEM 1A.
Risk Factors
    
Except as set forth below, there have been no material changes in the risk factors applicable to us from those disclosed in our 2010 Form 10-K.
A majority of our current production, revenue and cash flow from operating activities is derived from assets that are concentrated in a single geographic area in which we have temporarily suspended drilling operations.
Substantially all of our estimated proved reserves at December 31, 2010 and substantially all of our production during 2010 were associated with our East Texas wells. Accordingly, if the level of production from these properties substantially declines or if the price of gas declines, it could have a material adverse effect on our overall production level and our revenue. Approximately 27% of our estimated proved reserves relate to wells in the Cotton Valley Sands and shallower layers as of December 31, 2010. Beginning in the third quarter of 2011, we plan to temporarily suspend drilling of Haynesville/Bossier wells. We currently intend to focus drilling and capital expenditures for the remainder of 2011 and in 2012 on new drilling programs for recently acquired properties in the DJ Basin of Wyoming targeting the Niobrara Formation and the Williston Basin of North Dakota and Montana targeting the Bakken/Sanish-Three Forks Formation. Our decisions to suspend drilling temporarily is expected to result in declines in production from our Haynesville/Bossier Shale and Cotton Valley properties until we recommence drilling on those properties.

We will have increased exposure to producing properties and operations in the Bakken formation in Montana and North Dakota region, which makes us vulnerable to risks associated with operating in this major geographic area.

Our 2011 acquisitions of undeveloped lease acreage in the Niobrara formation of the DJ Basin in Wyoming and the Bakken/Sanish-Three Forks formation in Montana and North Dakota expose us to the risks associated with operating in this geographic area, including, but not limited to, delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation (including any hydraulic fracturing regulations), natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.


33

Shortages or increases in costs of equipment, services and qualified personnel could delay the drilling of wells and result in a reduction in the amount of cash available for capital investment.
 
We have recently acquired a significant amount of undeveloped acreage. We may need to hire additional qualified personnel to effectively implement our Williston and DJ Basin drilling programs. The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and gas industry can fluctuate significantly, often in correlation with oil, natural gas and natural gas liquids prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil, natural gas and natural gas liquids prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could significantly hinder our ability to perform the drilling obligation and delay completion of the wells, which could have a material adverse effect on our financial condition and results of operations.
We have entered into long-term rig contracts, which will require a significant portion of our budgeted capital expenditures over their terms.
In 2008, we entered into agreements with Helmerich & Payne for four new FlexRigs™ for three-year terms each. As of June 30, 2011, we would be obligated to pay $18.7 million if we were to terminate the remaining terms of these agreements. This represents a significant portion of our future capital expenditures budget. We have entered into sublease agreements for all four of these FlexRigs, two of which are for the balance of the term; however, the subleases do not cover our entire obligations under the agreements. These commitments will limit our ability to deploy our capital to other projects. Additionally, the term of these commitments restrict our flexibility to adjust the scale of our drilling efforts based on prevailing commodity prices and other industry conditions, meaning that we will continue to be obligated to pay for these rigs even if market conditions do not render their use economical for us. As such, these long-term commitments could have an adverse effect on our financial condition and results of operations.
During June 2011, we entered into a one-year rig lease agreement for $24,500 per day for a total obligation of $9.0 million. We plan to use this rig for our drilling program in the Bakken. If our current drilling program were not to utilize this rig fully, this long-term commitment could have an adverse effect on our financial condition and results of operations.
Increased drilling in our recently acquired properties in Wyoming, Montana and North Dakota may cause pipeline capacity problems that limit our ability to sell natural gas and oil.
There are crude oil and natural gas pricing and take-away risks in the Bakken and Niobrara basins. In the Bakken, producers sell their crude oil to marketers who take delivery and title at the producer's tank battery facilities and transport the crude to markets for resale. Crude oil is trucked from the producer's tank batteries to both pipelines and rail facilities whose available capacity can be curtailed in the winter season due to inclement weather. There is currently 500,000 Bbls of take-away capacity which is comprised of approximately 385,000 Bbls of pipeline capacity and 115,000 Bbls of rail capacity. Third parties have announced expansion projects totaling approximately 1,134,000 Bbls of new capacity projects that may become available over the next 12 months. The average differences between the WTI crude oil price and the North Dakota Crude Oil First Purchase Price for the year ended December 31, 2010 and the six months ended June 30, 2011 was $9.24 per Bbl and $8.01 per Bbl, respectively.
Natural gas produced in the Bakken has a high Btu content that requires gas processing to remove the natural gas liquids before it can be redelivered into transmission pipelines; this is done by either producers or third party processors, who currently operate a total of 15 plants. There is over 3.0 Bcf per day of natural gas take-away capacity on transmission pipelines; the capacity is currently fully subscribed, though the entire capacity is not currently being utilized. There have been announced additional capacity projects totaling over 1.0 Bcf per day that are scheduled to go in service in the second half of 2011. The natural gas prices realized by producers in the Bakken are a function of the NYMEX price, less transportation costs, plus the upgrade received from the proceeds related to the natural gas liquids that are extracted and sold separately.
Natural gas produced in the Niobrara has a high Btu content that requires gas processing to remove the natural gas liquids before it can be redelivered into transmission pipelines; this is done by either producers or third party processors. There is over 6.0 Bcf per day of natural gas take-away capacity on transmission pipelines; the capacity is currently fully subscribed, although approximately 40% of the capacity is not currently being utilized. There have been announced additional capacity projects totaling over 2.85 Bcf per day that are scheduled to go in service in 2011. Though transmission capacity exists, extensive gas gathering infrastructure does not currently exist in the counties in which we will operate, and will need to be built by producers or pipeline companies. The natural gas prices realized by producers in the Niobrara are a function of the NYMEX price, less transportation costs, plus the upgrade received from the proceeds related to the natural gas liquids that are extracted and sold separately. In the Niobrara, producers sell their crude oil to marketers who take delivery and title at the producer's tank battery

34

facilities, and transport the crude to markets for resale. Crude oil is trucked from the producer's tank batteries to pipelines whose available capacity can be curtailed in the winter season due to inclement weather. There is currently 200,000 Bbls of pipeline take-away capacity. The average difference between the WTI crude oil price and the Wyoming Crude Oil First Purchase Price for the year ended December 31, 2010 and the six months ended June 30, 2011 was $11.29 per Bbl and $14.00 per Bbl, respectively.
Such fluctuations and discounts could have a material adverse effect on our financial condition and results of operations.
Hedging our production may result in losses or limit potential gains.
We enter into hedging arrangements to limit our exposure to the volatility in the prices of oil and natural gas and provide stability to cash flows. As of June 30, 2010, we had entered into derivative instruments that include crude oil and natural gas swaps, collars, three-way collars, and put spreads. As of June 30, 2011, we had natural gas hedges in place of 7.8 Bcf for our remaining estimated natural gas production for 2011 at an average hedge floor price of $6.13 per Mcf. In addition, we have 16.7 Bcf and 4.7 Bcf of natural gas hedged in 2012 and 2013, respectively, at average hedge prices of $6.08 and $5.40 per Mcf. As of June 30, 2011, we have also sold put options that would reduce the average hedge floor price if the monthly natural gas contract settlement price is below $4.18 for 2011, $4.12 for 2012 and $3.75 for 2013. If the monthly natural gas contract settlement is below the average sold put price, we will receive the monthly natural gas contract settlement price plus $1.95 in 2011, $1.95 in 2012, and $1.65 in 2013. Hedging arrangements expose us to risk of financial loss in some circumstances, including the following:
•
production is substantially less than expected;
•
the counter-party to the hedging contract defaults on its contractual obligations; and
•
there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.
 
In addition, these hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas. Additionally, derivatives that are not hedges must be adjusted to fair value through income. If the derivative qualifies and is designated as a cash flow hedge, the effective portion of changes in the fair value of the derivative is recognized in other comprehensive income (loss) until the hedged item is recognized in income. The ineffective portion of a derivative's change in fair value, as measured using the dollar offset method, is immediately recognized in gain (loss) from oil and natural gas hedging activities in the statement of operations.
If it is probable the oil or natural gas sales that are hedged will not occur, hedge accounting must be discontinued, and the gain or loss reported in accumulated other comprehensive income (loss) is immediately reclassified into income. If a derivative that qualified for cash flow hedge accounting ceases to be highly effective, or is liquidated or sold prior to maturity, hedge accounting must be discontinued. The gain or loss associated with the discontinued hedges remains in accumulated other comprehensive income (loss) and is reclassified into income as the hedged transactions occur.
While the primary purpose of our derivative transactions is to protect ourselves against the volatility in oil and natural gas prices, under certain circumstances, or if hedges are deemed ineffective, discontinued, or terminated for any reason, we may incur substantial losses in closing out our positions, which could have a material adverse effect on our financial condition, results of operations, and cash flows. If we choose not to engage in hedging arrangements in the future, we may be more adversely affected by changes in oil and natural gas prices than our competitors, who may or may not engage in hedging arrangements.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the production of oil and natural gas, including from the developing shale plays. A decline in drilling of new wells and related servicing activities caused by these initiatives could adversely affect our financial position, results of operations and cash flows.
We use hydraulic fracturing in many of our wells, including in our Haynesville/Bossier wells, and plan to use hydraulic fracturing in wells drilled in our 2011 acquired acreage located in Wyoming, Montana and North Dakota. The Federal Energy Policy Act of 2005 amended the Underground Injection Control (“UIC”) provisions of the federal Safe Drinking Water Act (“SDWA”) to exclude certain hydraulic fracturing practices from the definition of “underground injection.” The EPA has asserted regulatory authority over certain hydraulic fracturing activities involving diesel fuel and has begun the process of drafting guidance relating to such practices. In addition, repeal of the SDWA exclusion of hydraulic fracturing has been advocated by certain advocacy organizations and others in the public. In March 2011, companion bills entitled the Fracturing Responsibility and Awareness of Chemicals (FRAC) Act were reintroduced in the United States Senate and House of Representatives. These bills, which are currently under consideration by Congress, would repeal the exemption for hydraulic fracturing from the SDWA, which would have the effect of allowing the EPA to promulgate new regulations and permitting

35

requirements for hydraulic fracturing, and would require the disclosure of the chemical constituents of hydraulic fracturing fluids to a regulatory agency, which would make the information public via the Internet. Additionally, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing, the initial results of which are expected to be available by late 2012 and the final results of which are expected in 2014. The U.S. Department of the Interior has also announced that it will consider regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents. In addition, some states and localities, including Texas and Wyoming, have adopted, and others are considering adopting, laws regulations or ordinances that could restrict or ban hydraulic fracturing in certain circumstances, that would require, with some exceptions, disclosure of constituents of hydraulic fracturing fluids, or that would impose higher taxes, fees or royalties on natural gas production. Moreover, public debate over hydraulic fracturing and shale gas production has been increasing, and has resulted in delays of well permits in some areas
During the 111th Congress, the former Chairman of the House Energy and Commerce Committee initiated an investigation of the potential impacts of hydraulic fracturing, which involved seeking information about fracturing activities and chemicals from certain companies in the oil and gas sector. It is possible that similar measures will be considered in the 112th Congress.
These proposals may lead to additional levels of regulation at the federal, state or local level that could cause operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.
There has been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts on drinking water supplies, use of waters, and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated in Texas and other states implicating hydraulic fracturing practices. Additional legislation or regulation could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of crude oil and natural gas, including from the developing shale plays, incurred by our customers or could make it more difficult to perform hydraulic fracturing. If these legislative and regulatory initiatives cause a material decrease in the drilling of new wells and related servicing activities, our business and profitability could be materially impacted.
We are subject to various legal proceedings and claims arising in the normal course of business. The cost of our defending these lawsuits and any future lawsuits, and any resulting judgments, could have a material adverse effect upon our business and financial condition.
We are party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to the Company and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, our estimates of the outcomes of such matters, and our experience in contesting, litigating, and settling similar financial position or results of operations after consideration of recorded accruals.
A putative class action lawsuit was filed by purported stockholders of the Northumberland County Retirement System and Oklahoma Law Enforcement Retirement System 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, respectively, in late April 2011. The complaint alleges that the registration statement and the prospectus for the offering contained material misstatements and omissions and seek 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. The federal court stayed all further proceedings in this case until after it decides whether to remand the case to state court. If the case remains in federal court, plaintiffs are expected to seek to be appointed lead plaintiff under the Private Securities Litigation Reform Act and to file an amended complaint thereafter. 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. No assurance can be given regarding the outcome of these legal proceedings, and additional claims may arise in the future.
Depending on the outcome of legal proceeding and claims, we may be required to pay material damages and fines, consent to injunctions on future conduct, or suffer other penalties, remedies or sanctions that could have a material adverse effect on our business and financial condition. In addition, our attention may be diverted from our ordinary business operations and we may incur significant expenses as a result of our defense of such claims (including substantial fees of lawyers and other

36

professional advisors and potential obligations to indemnify officers and others who are parties to such actions), which could have a material adverse effect on our business and financial condition.

We have received comments from the SEC staff (the "Staff") in connection with the staff's review of a registration statement and our annual report on Form 10-K for 2010 and our definitive proxy statement filed on April 22, 2011. The Staff's review is not yet complete, and we may be required to make changes to our filings in order to respond to the SEC Staff's comments.

In connection with a review of a registration statement and related review of certain other periodic filings, the Staff provided us with comments. The comments relating to our annual report on Form 10-K for the year ended December 31, 2010 included requests for additional disclosure regarding our hydraulic fracturing activities. The Staff's comments also included requests for additional information relating to changes to our estimated proved developed reserves in 2010 and changes to our oil and gas reserves in 2009 and 2008. We have responded to the Staff's comments.
 
It is possible the Staff will raise additional comments or require future disclosures. If our responses are not satisfactory or the Staff raises additional comments, we may be required to amend our filings to provide additional hydraulic fracturing disclosures or to lower the amount of reserves reported. Any changes to reserves reported could in turn require a restatement of our financial statements for prior periods. Any such amendments or restatements could have an adverse effect on the market price for our securities.


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 three months ended June 30, 2011.

ITEM 3.
Defaults Upon Senior Securities
None.

ITEM 4.
Removed and Reserved

ITEM 5.
Other Information.
None.

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


37

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
GMX RESOURCES INC.
 
 
 
Date:
August 8, 2011
/s/ James A. Merrill
 
 
James A. Merrill
 
 
Chief Financial Officer


38

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
 
 
3.2
 
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
 
Certificate of Designation of 9.25% Series B Cumulative Preferred Stock
 
8-A12B
 
001-32977
 
4.1
 
8/8/2006
 
 
4.1(a)
 
Rights Agreement dated May 17, 2005 by and between GMX Resources Inc. and UMB Bank, N.A., as Rights Agent
 
8-K
 
000-32325
 
4.1
 
5/18/2005
 
 
4.1(b)
 
Amendment No. 1 to Rights Agreement dated February 1, 2008
 
8-A/A
 
001-32977
 
4.1
 
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
 
Indenture dated October 28, 2009, between GMX Resources Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee
 
8-K
 
001-32977
 
4.1
 
10/28/2009
 
 
4.4
 
Supplemental Indenture dated October 28, 2009, between GMX Resources Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee
 
8-K
 
001-32977
 
4.2
 
10/28/2009
 
 
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
 
Registration Rights Agreement dated February 11, 2008, between GMX Resources Inc. and Jefferies Funding LLC
 
8-K
 
001-32977
 
10.4
 
2/15/2008
 
 
4.7
 
Registration Rights Agreement dated February 9, 2011, between GMX Resources Inc., the Guarantors named therein, and Credit Suisse Securities (USA) LLC and Morgan Stanley & Co. Incorporated, as representatives of the Initial Purchasers
 
8-K
 
001-32977
 
4.3
 
2/9/2011
 
 
4.8
 
Registration Rights Agreement dated February 28, 2011 between GMX Resources Inc. and Retamco Operating, Inc.
 
8-K
 
001-32977
 
10.1
 
3/2/2011
 
 
10.1(a)
 
Form of Non-Employee Director Restricted Stock Award Agreement
 
 
 
 
 
 
 
 
 
*
10.1(b)
 
Form of Employee Restricted Stock Award Agreement
 
 
 
 
 
 
 
 
 
*
10.2
 
Form of Cash Bonus Award Agreement
 
 
 
 
 
 
 
 
 
*
 

39

 
 
 
 
Incorporated by Reference
 
 
Exhibit No.
 
Exhibit Description
 
Form
 
SEC File
No.
 
Exhibit
 
Filing Date
 
Filed
Herewith
31.1
 
Rule 13a-14(a) Certification of Chief Executive Officer
 
 
 
001-32977
 
 
 
 
 
*
31.2
 
Rule 13a-14(a) Certification of Chief Financial Officer
 
 
 
001-32977
 
 
 
 
 
*
32.1
 
Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350
 
 
 
001-32977
 
 
 
 
 
*
32.2
 
Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350
 
 
 
001-32977
 
 
 
 
 
*
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
 
 
 
 
 
 
 
 
 
*


40

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