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EX-31.2 - RULE 13A-14(A) CERTIFICATION OF CHIEF FINANCIAL OFFICER - GMX RESOURCES INCdex312.htm
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Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2011

 

¨ 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  ¨

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  ¨    No  ¨

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

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

The number of shares outstanding of the registrant’s common stock as of May 9, 2011 was 59,970,359, which included 2,640,000 shares under a share loan which will be returned to the registrant upon conversion of certain outstanding convertible notes.

 

 

 


Table of Contents

GMX Resources Inc.

Form 10-Q

For the Quarter Ended March 31, 2011

TABLE OF CONTENTS

 

PART I. FINANCIAL INFORMATION     3   
ITEM 1.   Financial Statements     3   
ITEM 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operation.     18   
ITEM 3.   Quantitative and Qualitative Disclosures About Market Risk     24   
ITEM 4.   Controls and Procedures     26   
PART II. OTHER INFORMATION     27   
ITEM 1.   Legal Proceedings     27   
ITEM 1A.   Risk Factors     27   
ITEM 2.   Unregistered Sales of Equity Securities and Use of Proceeds     27   
ITEM 6.   Exhibits     27   
SIGNATURES     28   

 

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Table of Contents

PART I. FINANCIAL INFORMATION

 

ITEM 1. Financial Statements

GMX Resources Inc. and Subsidiaries

Consolidated Balance Sheets

(dollars in thousands, except share data)

(Unaudited)

 

     March 31,
2011
    December 31,
2010
 
ASSETS     

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 77,641      $ 2,357   

Accounts receivable – interest owners

     4,724        5,339   

Accounts receivable – oil and natural gas revenues, net

     5,832        6,829   

Derivative instruments

     16,996        19,486   

Inventories

     326        326   

Prepaid expenses and deposits

     5,870        5,767   

Assets held for sale

     24,309        26,618   
                

Total current assets

     135,698        66,722   
                

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

    

Properties being amortized

     994,085        938,701   

Properties not subject to amortization

     73,174        39,694   

Less accumulated depreciation, depletion, and impairment

     (690,040     (630,632
                
     377,219        347,763   
                

PROPERTY AND EQUIPMENT, AT COST, NET

     68,573        69,037   

DERIVATIVE INSTRUMENTS

     14,173        17,484   

OTHER ASSETS

     10,943        6,084   
                

TOTAL ASSETS

   $ 606,606      $ 507,090   
                
LIABILITIES AND EQUITY     

CURRENT LIABILITIES:

    

Accounts payable

   $ 20,401      $ 24,919   

Accrued expenses

     25,561        33,048   

Accrued interest

     5,553        3,317   

Revenue distributions payable

     5,831        4,839   

Current maturities of long-term debt

     26        26   
                

Total current liabilities

     57,372        66,149   
                

LONG-TERM DEBT, LESS CURRENT MATURITIES

     340,230        284,943   

DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS

     8,240        10,622   

OTHER LIABILITIES

     7,259        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, 2,341,807 shares issued and outstanding as of March 31, 2011 and 2,041,169 shares issued and outstanding as of December 31, 2010 (aggregate liquidation preference $58,545,175 as of March 31, 2011 and $51,029,255 as of December 31, 2010)

     2        2   

Common stock, par value $.001 per share – 100,000,000 shares authorized, 55,731,534 shares issued and outstanding as of March 31, 2011 and 31,283,353 shares issued and outstanding as of December 31, 2010

     56        31   

Additional paid-in capital

     646,339        531,944   

Accumulated deficit

     (485,234     (430,784

Accumulated other comprehensive income, net of taxes

     12,449        15,227   
                

Total GMX Resources’ equity

     173,612        116,420   

Noncontrolling interest

     19,893        21,799   
                

Total equity

     193,505        138,219   
                

TOTAL LIABILITIES AND EQUITY

   $ 606,606      $ 507,090   
                

See accompanying notes to consolidated financial statements.

 

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Table of Contents

GMX Resources Inc. and Subsidiaries

Consolidated Statements of Operations

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

(Unaudited)

 

     Three Months Ended
March  31,
 
     2011     2010  

OIL AND GAS SALES, net of gain from ineffectiveness of derivatives of $408 and $530, respectively

   $ 29,376      $ 21,300   

EXPENSES:

    

Lease operations

     2,898        3,111   

Production and severance taxes

     383        710   

Depreciation, depletion, and amortization

     12,789        6,370   

Impairment of oil and natural gas properties and assets held for sale

     48,320        —     

General and administrative

     7,077        7,187   
                

Total expenses

     71,467        17,378   
                

Income (loss) from operations

     (42,091     3,922   

NON-OPERATING INCOME (EXPENSES):

    

Interest expense

     (8,022     (4,229

Loss on extinguishment of debt

     (108     —     

Interest and other income

     269        24   

Unrealized losses on derivatives

     (444     (221
                

Total non-operating expense

     (8,305     (4,426
                

Loss before income taxes

     (50,396     (504

INCOME TAX (PROVISION) BENEFIT

     (1,432     5,788   
                

NET (LOSS) INCOME

     (51,828     5,284   

Net income attributable to noncontrolling interest

     1,412        313   
                

NET (LOSS) INCOME APPLICABLE TO GMX RESOURCES

     (53,240     4,971   

Preferred stock dividends

     1,210        1,156   
                

NET (LOSS) INCOME APPLICABLE TO COMMON SHAREHOLDERS

   $ (54,450   $ 3,815   
                

(LOSS) EARNINGS PER SHARE – Basic

   $ (1.29   $ 0.14   
                

(LOSS) EARNINGS PER SHARE – Diluted

   $ (1.29   $ 0.14   
                

WEIGHTED AVERAGE COMMON SHARES – Basic

     42,150,589        28,097,699   
                

WEIGHTED AVERAGE COMMON SHARES – Diluted

     42,150,589        28,097,699   
                

See accompanying notes to consolidated financial statements.

 

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Table of Contents

GMX Resources Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(dollars in thousands)

(Unaudited)

 

     Three Months Ended
March  31,
 
     2011     2010  

CASH FLOWS DUE TO OPERATING ACTIVITIES

    

Net income (loss)

   $ (51,828   $ 5,284   

Depreciation, depletion, and amortization

     12,789        6,370   

Impairment of oil and natural gas properties and assets held for sale

     48,320        —     

Deferred income taxes

     1,431        (5,757

Non-cash compensation expense

     1,159        2,435   

Loss (gain) on extinguishment of debt

     108        —     

Non-cash interest expense

     2,403        2,233   

Other

     37        (310

Decrease (increase) in:

    

Accounts receivable

     1,613        2,649   

Inventory and prepaid expenses

     (322     (398

Increase (decrease) in:

    

Accounts payable and accrued liabilities

     (155     (2,646

Revenue distributions payable

     992        601   
                

Net cash provided by operating activities

     16,547        10,461   
                

CASH FLOWS DUE TO INVESTING ACTIVITIES

    

Purchase of oil and natural gas properties

     (85,872     (32,730

Purchase of property and equipment

     (935     (3,026

Proceeds from dispositions of property and equipment, oil and gas properties and assets held for sale

     2,079        —     
                

Net cash used in investing activities

     (84,728     (35,756
                

CASH FLOWS DUE TO FINANCING ACTIVITIES

    

Borrowings on revolving bank credit facility

     18,000        —     

Payments on debt

     (110,022     (31

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

     6,915        —     

Dividends paid on Series B preferred stock

     (1,210     (1,156

Fees paid related to financing activities

     (15,890     —     

Contributions from non-controlling interest member

     60        225   

Distributions to non-controlling interest member

     (3,378     (280
                

Net cash provided by (used in) financing activities

     143,465        (1,242
                

NET INCREASE DECREASE IN CASH

     75,284        (26,537

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD

     2,357        35,554   
                

CASH AND CASH EQUIVALENTS AT END OF PERIOD

   $ 77,641      $ 9,017   
                

SUPPLEMENTAL CASH FLOW DISCLOSURE

    

CASH PAID DURING THE PERIOD FOR:

    

INTEREST, Net of amounts capitalized

   $ 4,318      $ 2,750   

INCOME TAXES, Paid (Received)

   $ 1      $ (31

NON-CASH INVESTING AND FINANCING ACTIVITIES

    

Additions to oil and natural gas properties from issuance of common stock

   $ 13,614      $ —     

(Increase) decrease in accounts payable for property additions

   $ 10,624      $ (4,246

See accompanying notes to consolidated financial statements.

 

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Table of Contents

GMX Resources Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income

(dollars in thousands)

(Unaudited)

 

     Three Months Ended
March  31,
 
     2011     2010  

Net (loss) income

   $ (51,828   $ 5,284   

Other comprehensive income (loss), net of income tax:

    

Change in fair value of derivative instruments, net of income tax of $80 and $6,190, respectively

     156        12,017   

Reclassification of gain on settled contracts, net of income taxes ($1,511) and ($1,238), respectively

     (2,934     (2,402
                

Comprehensive (loss) income

     (54,606     14,899   

Comprehensive income attributable to the noncontrolling interest

     1,412        313   
                

Comprehensive (loss) income attributable to GMX shareholders

   $ (56,018   $ 14,586   
                

See accompanying notes to consolidated financial statements.

 

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Table of Contents

GMX Resources Inc.

Condensed Notes To Interim Financial Statements

Three months ended March 31, 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 quarter of 2011 to acquire core positions in over 65,000 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. 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 transactions are as follows:

 

   

Niobrara acquisition—an agreement to purchase all of the working interest and an 80% net revenue interest in approximately 30,451 undeveloped acres of oil and gas leases located in the Niobrara basin in Wyoming for approximately $27.4 million, including commissions. The Company closed the transaction relating to these properties on February 14, 2011. 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—a purchase and sale agreement, entered into on January 13, 2011, relating to the acquisition by the Company of all of the working interest and an 80% net revenue interest in approximately 17,797 undeveloped net acres of oil and gas leases located in the Bakken formation in Montana and North Dakota. Pursuant to this agreement, as consideration for the oil and gas leases, we issued to the seller, Retamco Operating, Inc., at the closing of this transaction on February 28, 2011, 2,268,971 shares of common stock and approximately $4.2 million in cash. At the closing, the Company also entered into a registration rights agreement with this seller relating to the resale of the shares of common stock received in this transaction.

 

   

Niobrara acquisition-Retamco—a separate purchase and sale agreement with Retamco Operating, Inc. relating to the acquisition by the Company of all of the working interest and an 80% net revenue interest in approximately 9,809 undeveloped net acres of oil and gas leases located in the Niobrara basin in Wyoming. The purchase price for this transaction is approximately $24.0 million in cash. On April 6, 2011, we completed the purchase of 9,282 acres for $22.7 million with the remaining 527 acres to be purchased prior to May 31, 2011.

 

   

Bakken acquisitions-Arkoma Bakken and other parties—a purchase and sale agreement, dated as of January 24, 2011, and a letter of intent, with Arkoma Bakken, LLC and other sellers with respect to undeveloped acreage located in the Bakken formation in North Dakota. These agreements provide for consideration payable in cash and in our common stock. The stock consideration will be based on a volume weighted average closing price of our common stock on the NYSE during the 15 trading days immediately prior to and including the date three trading days prior to the closing date; provided in the event such calculated price is less than $5.50, the price used will be $5.50, and in the event such calculated price is more than $6.50, the price used will be $6.50. The first purchase and sale agreement was closed on April 28, 2011 and relates to the acquisition by us of 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 $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 also entered into a stockholder and registration rights agreement with these sellers at closing relating to the resale of the shares of common stock received by them in this transaction and piggyback registration rights in

 

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the event the Company proposes to offer and sell shares of its common stock in an underwritten public offering during the effective period of the agreement. The sellers have agreed, pursuant to the stockholder and registration rights agreement, not to sell, pledge or otherwise dispose of, directly or indirectly the shares of common stock received by them for six months following April 28, 2011.

The letter of intent and proposed second purchase and sale agreement relating to the acquisition of 87.5% working interest and an 80% net revenue interest in approximately 1,862 net acres in Williams County, North Dakota (with the acquired interest representing 1,629 net acres) has been terminated by the Company due to title failure. The aggregate purchase price for these properties was expected to be approximately $7.3 million.

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. A 40% membership interest in Endeavor Gathering is owned by Kinder Morgan Endeavor LLC (“KME”).

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 March 31, 2011, and the results of its operations and its cash flows for the three months ended March 31, 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 months ended March 31, 2011, the instruments mentioned above would decrease diluted loss per share, which would result in antidilutive instruments. Therefore, there were no dilutive shares as of March 31, 2011. Due to depressed share prices, it was determined that there were no dilutive shares at March 31, 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 March 31, 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 March 31, 2011 and 2010, future net revenues are calculated using prices that represent the average of the first day of the month price for the 12-month period prior to the end of the period.

Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. Based on average prices for the prior 12-month period for natural gas and oil as of March 31, 2011, these cash flow hedges increased the full-cost ceiling by $49.8 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 $70.3 million, we would have incurred a ceiling test write-down of $37.5 million for the three months ended March 31, 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 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. Due to natural gas representing 92% of the Company’s total production, a decrease in natural gas prices can significantly impact the Company’s ceiling test. During the first quarter of 2011, the 12-month average of the first day of the month natural gas price decreased 6% from $4.38 per MMbtu at December 31, 2010 to $4.10 per MMbtu at March 31, 2011. As a result of the Company’s ceiling test as of March 31, 2011 and 2010, the Company recorded impairment expense of $48.1 million and $0, respectively.

 

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For the impairment charge recorded in the first quarter of 2011, $14.5 million of the $48.1 million charge was related to the acquisition cost of undeveloped acreage subject to the impairment test, based on the Company’s decision during the quarter 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.

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.

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.

 

     March 31, 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

     69,403         68,021         116,365         105,258   

4.50% Convertible Senior Notes due May 2015

     75,774         70,725         75,238         63,825   

11.375% Senior Notes due February 2019

     193,735         196,000         —           —     

Joint venture financing(2)

     1,344         1,344         1,366         1,366   
                                   

Total

   $ 340,256       $ 336,090       $ 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 secured revolving credit facility.

The Restated Loan Agreement provides for a line of credit of up to $100.0 million (the “commitment”), subject to a borrowing base (“borrowing base”). The initial borrowing base availability under the Restated Loan Agreement is $60.0 million. The amount of

 

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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 a Second Amendment to Restated Loan Agreement, dated effective as of March 1, 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 $62,000,000; 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.

The loans under our Restated Loan Agreement bear interest at a rate elected by the Company which is based on the prime rate, LIBOR or federal funds rate plus margins ranging from 1% to 3.50% depending on the base rate used and the amount of loans outstanding in relation to the borrowing base. We may voluntarily prepay the loans without premium or penalty. If and to the extent the loans outstanding exceed the most recently determined borrowing base, the loan excess will be mandatorily 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 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 March 31, 2011 are shown below:

 

Financial Covenant

   Required Ratio    Actual
Ratio
 

Current ratio (1)

   Not less than 1 to 1      3.11 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      3.11 to 1   

 

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(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 million as of March 31, 2011) to current liabilities. The calculation will not include the effects, if any, of derivatives under ASC 815. As of March 31, 2011, current assets included derivatives assets of $17.0 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 March 31, 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 March 31, 2011 (amounts in thousands):

 

Net loss

   $ (195,407

Plus:

  

Interest expense

     22,435   

Impairment of oil and natural gas properties

     192,033   

Depreciation, depletion and amortization

     44,480   

Non-cash compensation and other expenses

     2,643   

Income tax benefit

     2,981   

Less:

  

Gain on extinguishment of debt

     (33
        

EBITDA

   $ 69,132   
        

 

(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 March 31, 2011, cash interest expense included fees paid related to bank financing activities and other loan fees of $1.6 million. As of March 31, 2011, non-cash interest expense of $7.9 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 $3.0 million was added to interest expense.

As of March 31, 2011, the Company was in compliance with all financial covenants under the revolving bank credit facility.

5.00% Convertible Senior Notes

As of March 31, 2011 and December 31, 2010, the net carrying amount of the 5.00% convertible notes was as follows (amounts in thousands):

 

     March 31, 2011     December 31, 2010  

Principal amount

   $ 72,750      $ 122,750   

Less: Unamortized debt discount

     (3,347     (6,385
                

Carrying amount

   $ 69,403      $ 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 months ended March 31, 2011 and 2010 was $1.4 million and $1.6 million, respectively. The amount of non-cash interest expense for the three months ended March 31, 2011 and 2010 related to the amortization of the debt discount and amortization of the transaction costs was $0.8 million and $0.9 million, respectively.

 

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As of March 31, 2011, the unamortized discount is expected to be amortized into earnings over 1.8 years. The carrying value of the equity component of the 5.00% convertible notes was $3.9 million as of March 31, 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 FASB Accounting Standards Codification (“ASC”) 470-30-40. 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 $0.1 million for the three months ended March 31, 2011, presented in our consolidated statements of operations.

4.50% Convertible Senior Notes

As of March 31, 2011, the net carrying amount of the 4.50% convertible notes was as follows (amounts in thousands):

 

     March 31, 2011     December 31, 2010  

Principal amount

   $ 86,250      $ 86,250   

Less: Unamortized debt discount

     (10,476     (11,012
                

Carrying amount

   $ 75,774      $ 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 months ended March 31, 2011 and 2010 was $1.0 million. The amount of non-cash interest expense for the three months ended March 31, 2011 and 2010 related to the amortization of the debt discount and transaction costs was $0.7 million and $0.6 million, respectively. As of March 31, 2011, the unamortized discount is expected to be amortized into earnings over 4.1 years. The carrying value of the equity component of the 4.50% convertible notes was $8.4 million as of March 31, 2011.

11.375% Senior Notes

On February 9, 2011, the Company successfully completed the issuance and sale of $200,000,000 aggregate principal amount of 11.375% Senior Notes due 2019 (the “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 March 31, 2011, the net carrying amount of the 11.375% Senior Notes was as follows (amounts in thousands):

 

     March 31, 2011  

Principal amount

   $ 200,000   

Less: Unamortized debt discount

     (6,265
        

Carrying amount

   $ 193,735   
        

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 months ended March 31, 2011 was $3.3 million. The amount of non-cash interest expense for the three months ended March 31, 2011 related to the amortization of the debt discount and transaction costs was $0.2 million. As of March 31, 2011, the unamortized discount is expected to be amortized into earnings over 7.9 years.

 

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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 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 111.375% of their principal amount plus accrued interest, provided that: (i) at least 65% of the aggregate principal amount of the notes originally issued remains outstanding after the redemption; and (ii) the redemption occurs within 90 days after the closing of the related public offering.

At any time on or prior to February 15, 2015, the Company may, at its option, redeem the 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.

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 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

 

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location and the futures contract delivery locations. Settlement or expiration of the hedges is designed to coincide as closely as possible with the physical sale of the commodity being hedged—daily for oil and monthly for natural gas—to obtain reasonable assurance that a gain in the cash sale will offset the loss on the hedge and vice versa.

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

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

   March 31,
2011
     December 31,
2010
     March 31,
2011
     December 31,
2010
     March 31,
2011
    December 31,
2010
 
          (in thousands)      (in thousands)      (in thousands)  

Derivatives designated as Hedging Instruments under ASC 815

                   

Natural gas

   Current derivative asset    $ 20,090       $ 23,187       $ 2,189       $ 2,963       $ 17,901      $ 20,224   

Natural gas basis

   Current derivative asset      —           —           545         566         (545     (566

Natural gas

   Derivative instruments – non-current asset      16,773         20,503         2,304         2,897         14,469        17,606   

Natural gas basis

   Derivative instruments – non-current asset      —           —           40         122         (40     (122
                                                       
      $ 36,863       $ 43,690       $ 5,078       $ 6,548       $ 31,785      $ 37,142   
                                                       

Derivatives not designated as Hedging Instruments under ASC 815

                   

Crude oil

   Current derivative asset    $ —         $ —         $ 360       $ 172       $ (360   $ (172

Crude oil

   Derivative instruments – non-current asset      —           —           256         —           (256     —     
                                                       
      $ —         $ —         $ 616       $ 172       $ (616   $ (172
                                                       

Net derivative fair value

                  $ 31,169      $ 36,970   
                               

The following table summarizes the outstanding natural gas and crude oil derivative contracts the Company had in place as of March 31, 2011:

 

Effective Date

   Maturity Date      Notional
Amount
Per
Month
     Remaining
Notional
Amount as
of March 31,
2011
     Additional
Put
Options
     Floor      Ceiling      Designation under
ASC 815
 

Natural Gas (MMBtu):

                    

4/1/2011

     12/31/2012         155,671         3,269,100             $ 7.00         Cash flow hedge   

4/1/2011

     12/31/2011         188,781         1,699,029             $ 8.00         Cash flow hedge   

4/1/2011

     10/31/2011         200,000         1,400,000       $ 5.00       $ 6.50       $ 8.30         Cash flow hedge   

4/1/2011

     10/31/2011         122,286         856,000             $ 5.40         Cash flow hedge   

11/1/2011

     3/31/2012         200,000         1,000,000       $ 5.50       $ 7.00            Cash flow hedge   

4/1/2011

     12/31/2012         1,048,571         22,020,000       $ 4.00       $ 6.00            Cash flow hedge   

4/1/2011

     3/31/2012         135,325         1,623,902       $ 4.00       $ 6.25            Cash flow hedge   

11/1/2011

     3/31/2012         180,000         900,000             $ 6.25         Cash flow hedge   

4/1/2012

     12/31/2012         232,331         2,090,976       $ 4.50       $ 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   

Crude Oil (Bbls):

                    

4/1/2011

     12/31/2011         3,056         27,500             $ 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.

 

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Effects of derivative instruments on the Consolidated Statement of Operations

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

There were no oil derivatives that qualified for hedges for the quarter ended March 31, 2010 and 2011. 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
March  31,
 
   Location of
Amounts
   2011      2010  

Amount of Gain Recognized in OCI on Derivative (Effective Portion)

   OCI      236         18,207   

Amount of Gain Reclassified from Accumulated OCI into Income (Effective Portion)

   Oil and Gas
Sales
     4,445         3,640   

Amount of Gain Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)

   Oil and Gas
Sales
     408         530   

Assuming that the market prices of oil and gas futures as of March 31, 2011 remain unchanged, the Company would expect to transfer a gain of approximately $7.3 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 for the three months ended:

 

     Location of Gain (Loss) Recognized in
Income on Derivative
   Amount of Gain (Loss) Recognized in
Income on Derivative
 
          March 31,
2011
    March 31,
2010
 
          (in thousands)  

Realized

       

Natural gas

   Oil and gas sales    $ —        $ (23

Unrealized

       

Natural gas

   Unrealized losses on derivatives      —          (221

Crude oil

   Unrealized losses on derivatives      (444     —     
                   
      $ (444   $ (244
                   

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 March 31, 2011 and December 31, 2010:

 

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     As of March 31, 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

   $ —         $ 31,785      $ —         $ —         $ 37,142      $ —     

Crude oil derivative instruments

   $ —         $ (616   $ —         $ —         $ (172   $ —     

NOTE D – STOCK COMPENSATION PLANS

We recognized $1.2 million and $2.4 million of stock compensation expense for the three months ended March 31, 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 & natural gas properties was $0.1 million and $0.6 million for the three months ended March 31, 2011 and 2010, respectively.

Restricted Stock

A summary of the status of our unvested shares of restricted stock and the changes for the years ended December 31, 2010 and the three months ended March 31, 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

     4,566      $ 4.38   

Vested

     (6,386   $ 10.20   

Forfeited

     (1,354   $ 21.88   
          

Unvested shares as of March 31, 2011

     688,822      $ 13.43   
          

As of March 31, 2011, there was $9.2 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 2.03 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 March 31, 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, GMX completed an offering of 21,075,000 shares of its common stock at a price of $4.75 per share. The net proceeds to the Company were $93.6 million after discounts and underwriters’ fees. 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 discounts and underwriters’ fees. 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

 

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purchase up to $50.0 million of its 5.00% convertible notes, (ii) repay the then outstanding balance under its secured revolving 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 the Bakken acquisition described in Note A.

During the first quarter of 2011, the Company received $6.9 million related to the issuance of 300,638 shares of its 9.25% Series B Cumulative Preferred Stock in registered sales by the Company.

NOTE F – INCOME TAXES

We recorded tax (provisions) benefits of $(1.4) million and $5.8 million for the three months ended March 31, 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 March 31, 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 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, on April 21, 2011. The complaint alleges that the registration statement and the prospectus for the offering contained material misstatements and omissions and seeking damages under Sections 11, 12 and 15 of the Securities Act of 1933 of an unspecified amount and rescission. 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.

NOTE H – SUBSEQUENT EVENTS

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 $31.2 million, of which approximately $10.4 million was paid in cash and the remainder of the purchase price was paid with stock consideration of 3,542,091 common shares (based on a 15 day volume weighted average value of $5.88 per share) At closing, the Company entered into a participation agreement with a joint operating agreement designating the Company as the operator of these properties. The Company has entered into a registration rights agreement with these sellers at closing relating to the resale of the shares of common stock received in this transaction. However, these sellers have agreed not to sell the shares of common stock received by them for six months following the closing of this transaction.

 

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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 historically engaged in the exploration, development and production of oil and natural gas from the Upper Bossier, Middle Bossier and Haynesville/Lower Bossier layers of the Bossier formulation (the “Haynesville/Bossier Shale”) and Cotton Valley Sands in the Schuler formation, in the Sabine Uplift of the Carthage, North Field of Harrison and Panola counties of East Texas (our “primary development area”). We consider and report all of our operations as one segment because our operating areas have similar economic characteristics and each meet the criteria for aggregation as defined in the Financial Accounting Standards Board Accounting Standards Codification 280.

During 2010, we focused on our Haynesville/Bossier Shale horizontal well development, which are substantially all natural gas wells. During the first quarter of 2011, we began to shift our focus from our core area into the Bakken and Niobrara formations in which we have acquired undeveloped acreage that consist of oil-focused resource plays as described below. We also intend to continue acreage acquisitions and to convert our unproved reserves to proved reserves, while maintaining balanced prudent financial management.

Our current strategy is to expand our assets into oil resource plays in several basins that will provide the Company the ability to optimize its capital allocation and create shareholder value. Our strategies emphasize:

 

   

Developing our undeveloped acreage in the Niobrara Formation and Bakken Formation—We have completed four transactions to acquire 24,458 net acres in the Bakken/Sanish-Three Forks oil resource play and 40,260 net acres. The Bakken and Niobrara plays have 136 and 532 net undeveloped horizontal locations, respectively, with an estimated average working interest between 70% and 45%. We currently intend to commence a two rig going to three rig multi-year 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.

 

   

Diversifying into higher margin crude oil production through the acquisition of the Bakken and Niobrara acreage—We plan to increase our profitability, operating cash flows and flexibility by deploying our working capital to increase oil production and reserves. As current and forecast crude oil and natural gas prices fluctuate, we will continue to evaluate our allocation of capital between our oil and natural gas resources.

 

   

Using our Haynesville/Bossier horizontal drilling and on-staff technical experience to economically develop our newly acquired Bakken and Niobrara acreage—Our team has drilled and completed 35 Haynesville/Bossier horizontal wells to date, and we continued to significantly reduce our completed well cost to under $1,400 per lateral foot in the first quarter of 2011 compared to $1,700 per lateral foot in the fourth quarter 2010. Our average number of days to drill a horizontal well increased to 31 days in the first quarter 2011 compared to an average of 29 days in the fourth quarter 2010. This was a result of the average lateral length increasing to 6,436 feet from 6,293 feet, respectively. We plan to utilize our experience and horizontal drilling efficiencies and advancements in the Bakken and Niobrara. We have assembled a technical staff with PhDs in Engineering and Geology and with Rocky Mountain experience, including the following basins: Powder River Basin, Williston Basin, Uinta Basin, San Juan Basin, Piceance Basin, D-J Basin, Wind River Basin, Greater Green River Basin, Shirley-Hannah Basin and Canadian Rockies. We have also assembled an experienced group of senior land executives with wide-ranging experiences in acquisition, integration, and operation in conventional and unconventional resource plays in more than one million acres,

 

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covering multiple-rig drilling programs over the past 25 years in the Anadarko (Woodford and Granite Wash), Arkoma (Fayetteville, Woodford Caney and CBM), Permian, Hugoton, Barnett Shale, Haynesville / Bossier Shale, Bakken and Three Forks, and Marcellus Shale basins.

 

   

Developing our existing Haynesville/Bossier Shale acreage—We seek to maximize the value of our existing legacy assets by developing these properties with the lowest risk and the highest production and reserve growth potential. We intend to continue to develop our multi-year inventory of drilling locations in the Haynesville/Bossier Shale in order to develop our natural gas reserves in our core area. We estimate that our approximate 32,700 net acres in our primary development area of the Haynesville/Bossier Shale includes as many as 257 net potential undrilled locations based on 80-acre spacing.

 

   

Maintaining operational control with focus on reducing operating costs—We have consistently maintained low finding and development costs and consistently operate with one of the lower operating cost structures in the industry. Our per unit lease operating expenses have declined 51% from $0.97 per Mcfe for the quarter ended March 31, 2010 to $0.48 per Mcfe for the quarter ended March 31, 2011.

 

   

Actively hedging production to provide greater certainty of cash flow and earnings—For 2011, 2012 and 2013, we have currently hedged approximately 15.5 million MMBtu, 16.7 million MMBtu and 4.7 million MMBtu of natural gas at a weighted average floor price of $6.11, $6.08, and $5.40 per MMbtu, respectively. We plan to continue to use hedging to mitigate commodity price risks.

The table below summarizes information concerning our operating activities in the three months ended March 31, 2011 compared to the three months ended March 31, 2010.

Summary Operating Data

 

     Three Months Ended
March  31,
 
     2011      2010  

Production:

     

Oil (MBbls)

     22         22   

Natural gas (MMcf)

     5,551         2,492   

Natural gas liquids (Mgals)

     2,515         4,018   

Gas equivalent production (MMcfe)

     6,040         3,199   

Average daily (MMcfe)

     67.1         35.5   

Average Sales Price:

     

Oil (per Bbl)

     

Sales price

   $ 92.34       $ 75.47   

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

     —           —     
                 

Total

   $ 92.34       $ 75.47   

Natural gas liquids (per gallon)

     

Sales price

   $ 0.85       $ 0.94   

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

     —           —     
                 

Total

   $ 0.85       $ 0.94   

Natural gas (per Mcf)

     

Sales price

   $ 3.67       $ 4.69   

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

     0.80         1.45   
                 

Total

   $ 4.47       $ 6.14   

Average sales price (per Mcfe)

   $ 4.80       $ 6.49   

Operating and Overhead Costs (per Mcfe):

     

Lease operating expenses

   $ 0.48       $ 0.97   

Production and severance taxes

     0.07         0.22   

General and administrative

     1.17         2.25   

Other (per Mcfe):

     

Depreciation, depletion and amortization—oil and natural gas properties

   $ 1.87       $ 1.63   

 

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Results of Operations for the Three Months Ended March 31, 2011 Compared to the Three Months Ended March 31, 2010

Oil and Natural Gas Sales. Oil and natural gas sales during the three months ended March 31, 2011 increased 38% to $29.4 million compared to the first quarter of 2010. Ineffectiveness of derivative gains recognized in oil and gas sales of $0.4 million and $0.5 million for the three months ended March 31, 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 an 89% increase in production on a Bcfe-basis and a 22% increase in oil prices, offset by a 27% decrease in the average realized price of natural gas and a 10% decrease in the average realized price in natural gas liquids (“NGLs”), 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 March 31, 2011 was $92.34, $0.85 and $3.67, respectively, compared to $75.47, $0.94 and $4.69, respectively, in the three months ended March 31, 2010. Our realized sales price for natural gas, including the effect of hedges of $0.80 and $1.45, for the three months ended March 31, 2011 and 2010, respectively, was approximately 109% and 117% of the average NYMEX closing contract price for the respective periods. In the first quarter of 2011 and 2010, the conversion of natural gas to NGLs produced an upgrade of approximately $0.25 per Mcf and $0.90 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.

Production of oil for the three months ended March 31, 2011 was consistent with the three months ended March 31, 2010 at 22 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 the production and revenues in our natural gas production and sales amounts. NGLs production for the three months ended March 31, 2011 decreased to 2,515 Mgals compared to 4,018 Mgals for the three months ended March 31, 2010, a decrease of 37%. This decrease was due to a decline in production in our non-Haynesville production, which have a higher NGL content versus our Haynesville/Bossier (“H/B”) horizontal wells. Natural gas production for the three months ended March 31, 2011 increased to 5,551 MMcf compared to 2,492 MMcf for the three months ended March 31, 2010, an increase of 123%. The increase in natural gas production resulted from production related to 34.1 net producing H/B horizontal wells that were on-line during the first quarter of 2011 compared to 14.9 net producing H/B horizontal wells online during the first quarter of 2010. For the period ending March 31, 2011, our H/B production increased 207% or 3,108 Mmcfe over the same period in 2010. During the first quarter of 2011, we brought on-line four H/B horizontal wells and production from H/B horizontal wells accounted for 76% of total production for the three months ended March 31, 2011 compared to 47% in the same period in 2010.

For the three months ended March 31, 2011, as a result of hedging activities but excluding derivative ineffectiveness, we recognized an increase in natural gas sales of $4.4 million compared to an increase in natural gas sales of $3.6 million in the first quarter of 2010. In the first quarter of 2011, hedging, excluding ineffectiveness, increased the average natural gas sales price by $0.80 per Mcf compared to an increase in natural gas sales price of $1.45 per Mcf in the first quarter of 2010. The Company did not recognize any oil related hedging activities in oil and natural gas liquid sales in the three months ended March 31, 2011 and 2010.

Lease Operations. Lease operations expense decreased $0.2 million, or 7%, for the three months ended March 31, 2011 to $2.9 million, compared to $3.1 million for the three months ended March 31, 2010. Lease operations expense on an equivalent unit of production basis decreased $0.49 per Mcfe in the three months ended March 31, 2011 to $0.48 per Mcfe, compared to $0.97 per Mcfe for the three months ended March 31, 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 decrease in lease operations expense is primarily related to a decrease in well workovers and repairs of approximately $0.4 million in the three months ended March 31, 2011 compared to the three months ended March 31, 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 46% to $0.4 million in the three months ended March 31, 2011 compared to $0.7 million in the three months ended March 31, 2010.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $6.4 million, or 100%, to $12.8 million in the three months ended March 31, 2011 compared to $6.4 million for the three months ended March 31, 2010. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.87 per Mcfe in the three months ended March 31, 2011 compared to $1.63 per Mcfe in the three months ended March 31, 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 March 31, 2011.

        Impairment of oil and natural gas properties. The primary factors impacting the full cost method ceiling test are expenditures added to the full cost pool, reserve levels and natural gas and oil prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value is generally written off as an expense. Due to natural gas representing 92% of the Company’s total production, a decrease in natural gas prices can significantly impact the Company’s ceiling test. During the first quarter of 2011, the 12-month average of the first day of the month natural gas price decreased 6% from $4.38 per MMbtu at December 31, 2010 to $4.10 per MMbtu at March 31, 2011. As a result of the Company’s ceiling test as of March 31, 2011 and 2010, the Company recorded impairment expense of $48.1 million and $0, respectively.

 

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For the impairment charge recorded in the first quarter of 2011, $14.5 million of the $48.1 million charge was 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, 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 Haynesville/Bossier 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 Haynesville/Bossier 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 for the three months ended March 31, 2011.

Our East Texas primary development area is located in central and eastern Harrison and Panola counties that is near acreage actively being drilled by other operators and has approximately 257 undrilled Haynesville/Bossier locations. As of March 31, 2011, we had 32,700 net acres in the primary development area represented by 18,137 net acres held by production, 6,337 net acres of non-operated acreage held by production and 8,226 net acres of undeveloped acreage, 14, 041 net acres (not included in the March 31, 2011 total) are expiring in 2011 represented by 3,406 acres in our primary development area, 9,750 acres outside our primary development area and 885 acres of non-operating acreage. Beyond 2011, we have 88 net acres expiring in 2012 and 10 net acres expiring in 2013. Based on our current drilling program, we expect to develop this acreage before it expires and therefore these costs have been excluded from our full cost ceiling test.

General and Administrative Expense. General and administrative expense for the three months ended March 31, 2011 was $7.1 million compared to $7.2 million for the three months ended March 31, 2010, a decrease of $0.1 million or 2%. General and administrative expense per equivalent unit of production was $1.17 per Mcfe for the first quarter of 2011 compared to $2.25 per Mcfe for the comparable period in 2010. During the three months ended March 31, 2010, the Company incurred approximately $1.5 million in severance costs of which $0.9 million or 62% was non-cash expense. Adjusting for severance costs incurred in the first quarter of 2010, general and administrative costs would have increased by $1.4 million from the three months ended March 31, 2010 compared to the three months ended March 31, 2011. The adjusted general and administrative expense per equivalent unit of production was $1.77 per Mcfe. The severance costs paid to terminated employees in the first quarter of 2010 were mostly offset by an increase in employee expenses related to the hiring of additional staff. General and administrative expenses include $1.2 million and $2.4 million of non-cash compensation expense as of the three months ended March 31, 2011 and 2010, respectively. Non-cash compensation represented 17% and 26% of total general and administrative expenses, excluding severance costs for the three months ended March 31, 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. We expect general and administrative expenses on a per Mcfe basis to decrease as production increases, excluding any non-cash compensation expense from stock based compensation plans.

Interest. Interest expense for the three months ended March 31, 2011 was $8.0 million compared to $4.2 million for the same period in 2010. For the three months ended March 31, 2011 and 2010, interest expense includes non-cash interest expense of $2.4 million and $2.2 million, respectively. As a result of the accounting for convertible bonds, Share Lending Agreement and deferred premiums on derivative instruments, our non-cash interest expense related to these financial instruments was $1.5 million and $1.8 million for the three months ended March 31, 2011 and 2010, respectively. Cash interest expense for the three months ended March 31, 2011 and 2010 was $5.6 million and $2.0 million, respectively. The increase in cash interest expense of $3.6 million was mainly due to the Company’s issuance and sale of $200 million aggregate principal amount of 11.375% Senior Notes due 2019 (“11.375% Senior Notes”) in February 2011.

Income Taxes. Income tax for the three months ended March 31, 2011 was an expense of $1.4 million as compared to a benefit of $5.8 million in the same period in 2010. The income tax expense and benefit recognized in the three months ended March 31, 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 noncontrolling interest: Net income to noncontrolling interest increased to $1.4 million for the three months ended March 31, 2011 compared to $0.3 million for the three months ended March 31, 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.

 

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Net Income and Net Income Per Share

Net Income and Net Income Per Share—Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2010. For the three months ended March 31, 2011 we reported a net loss applicable to common shareholders of $54.5 million and for the three months ended March 31, 2010, we reported net income applicable to common shareholders of $3.8 million. Net loss per basic and fully diluted share was $1.29 for the first quarter of 2011 compared to net income per basic and fully diluted share of $0.14 for the first quarter of 2010. Weighted average fully-diluted shares outstanding increased by 50% from 28,097,699 shares in the first quarter of 2010 to 42,150,589 shares in the first quarter of 2011.

Capital Resources and Liquidity

Our business is capital intensive. Our ability to grow our reserve base is dependent upon our ability to obtain outside capital and generate cash flows from operating activities to fund our drilling and capital expenditures. Our cash flows from operating activities are substantially dependent upon crude oil and natural gas prices, and significant decreases in market prices of crude oil or natural gas could result in reductions of cash flow and affect our drilling and capital expenditure plan. To mitigate a portion of our exposure to fluctuations in natural gas prices, we have entered into natural gas swaps, three-way collars and put spreads.

As of March 31, 2011, we had cash and cash equivalents of $77.6 million and working capital of $78.3 million. Through the period ended March 31, 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 common shares in February 2011, $6.9 million raised from the issuance of 300,638 shares of our 9.25% Series B Cumulative Preferred Stock preferred shares and $193.7 million, net of original issue discount, 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 senior notes due 2013 (“5.00% convertible notes”). The remaining proceeds from the offerings will be used to fund the Niobrara and Bakken acreage acquisitions and 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 three months of 2011, our capital expenditures were $73.9 million, net of additions to oil and gas properties from issuance of common stock for the Bakken and Niobrara acreage acquisitions, of which $69.3 million was primarily used for drilling and completing H/B horizontal wells, Niobrara and Bakken acreage acquisitions, land related activities and infrastructure. Cash expenditures related to the purchase price of the previously announced Niobrara and Bakken acreage acquisitions totaled $29.7 million for the first quarter of 2011.

In order to protect us against the financial impact of a decline in natural gas prices, we have an active, rolling three-year hedging program. As of March 31, 2011, we have natural gas hedges in place of 11.5 Bcf for our remaining estimated natural gas production for 2011 at an average hedge floor price of $6.12 per Mcf. In addition, we have 16.7 Bcf and 1.1 Bcf of natural gas hedged in 2012 and 2013, respectively, at average hedge prices of $6.08 and $5.25 per Mcf. As of March 31, 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 $4.17 for 2011, $4.13 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 $1.50 in 2013. In May 2011, we added a NYMEX natural gas swap at $5.45 for 10,000/Mmbtu per day for 2013. 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—Three months Ended March 31, 2011 Compared to Three months Ended March 31, 2010

In the three months ended March 31, 2011 and 2010, we spent $84.7 million and $35.8 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 three months ended March 31, 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 three months ended March 31, 2011 was $16.5 million compared to $10.5 million in the three months ended March 31, 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, 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 March 31, 2011, we had no funds drawn on our revolving bank credit facility that has a borrowing base of $60 million. Our next semi-annual redetermination is scheduled to be completed in October 1, 2011. The revolving credit facility contains various

 

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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 credit facility at March 31, 2011. For further discussion of our revolving credit facility, please also read Note B to the notes to unaudited financial statements included in this report.

Convertible Notes. We issued $125 million of 5.00% convertible senior notes due 2013 (“5.00% convertible notes”) 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 March 31, 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 March 31, 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.

Working Capital

At March 31, 2011, we had working capital of $78.3 million. Including availability under our revolving bank credit facility, our working capital as of March 31, 2011 would have been $138.3 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 10-K. There have been no changes in those policies.

Contractual Obligations

Our contractual obligations are summarized in our 2010 10-K. There have been no changes in those obligations.

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

Including, but not limited to, all of these reasons, actual results may vary materially from the forward looking statements and we cannot assure you that the assumptions used are necessarily the most likely. We will not necessarily update any forward looking statements to reflect events or circumstances occurring after the date the statement is made except as may be required by federal securities laws.

 

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ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

We are subject to price fluctuations for natural gas and crude oil. Prices received for natural gas and crude oil sold on the spot market are volatile due to factors beyond our control. 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 March 31, 2011:

 

Effective Date

   Maturity Date      Notional
Amount
Per

Month
     Remaining
Notional
Amount as
of March 31,
2011
     Additional
Put
Options
     Floor      Ceiling      Designation under
ASC 815
 

Natural Gas (MMBtu):

                    

4/1/2011

     12/31/2012         155,671         3,269,100             $ 7.00         Cash flow hedge   

4/1/2011

     12/31/2011         188,781         1,699,029             $ 8.00         Cash flow hedge   

4/1/2011

     10/31/2011         200,000         1,400,000       $ 5.00       $ 6.50       $ 8.30         Cash flow hedge   

4/1/2011

     10/31/2011         122,286         856,000             $ 5.40         Cash flow hedge   

11/1/2011

     3/31/2012         200,000         1,000,000       $ 5.50       $ 7.00            Cash flow hedge   

4/1/2011

     12/31/2012         1,048,571         22,020,000       $ 4.00       $ 6.00            Cash flow hedge   

4/1/2011

     3/31/2012         135,325         1,623,902       $ 4.00       $ 6.25            Cash flow hedge   

11/1/2011

     3/31/2012         180,000         900,000             $ 6.25         Cash flow hedge   

4/1/2012

     12/31/2012         232,331         2,090,976       $ 4.50       $ 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   

Crude Oil (Bbls):

                    

4/1/2011

     12/31/2011         3,056         27,500             $ 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 actual prices received by the Company.

The fair value of our natural gas and oil derivative contracts in effect at March 31, 2011 was $31.2 million, of which $17.0 million is classified as a current asset and $14.2 million is classified as a long-term asset.

 

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Based on the monthly notional amount for natural gas in effect at March 31, 2011, a hypothetical $0.10 increase in natural gas prices would have decreased the fair value from our natural gas swaps and options by $4.8 million and a $0.10 decrease in natural gas prices would have increased the fair value from our natural gas swaps and option by $4.8 million. Based on the monthly notional amount for crude oil in effect at March 31, 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 March 31, 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 3.25% to 4.75% 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 2.75% to 4.25% 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 2.75% to 4.25% 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 three 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%.

 

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ITEM 4. Controls and Procedures

Evaluation of disclosure controls and procedures as of March 31, 2011. As of the end of the period covered by this quarterly report, we have evaluated, and under the supervision and with the participation of senior management, including our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15(b) of the Exchange Act. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide us with reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosures. Based on this evaluation, as of the end of the period covered by this report, our principal executive officer and our principal financial officer have concluded that our disclosure controls and procedures were effective.

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

Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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PART II. OTHER INFORMATION

 

ITEM 1. Legal Proceedings

A putative class action, lawsuit was filed by 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, on April 21, 2011. The complaint alleges that the registration statement and the prospectus for the offering contained material misstatements and omissions and seeking damages under Sections 11, 12 and 15 of the Securities Act of 1933 of an unspecified amount and rescission. 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 financial position or results of operations after consideration of recorded accruals.

 

ITEM 1A. Risk Factors

There have been no material changes in the risk factors applicable to us from those disclosed in our 2010 10-K.

 

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 March 31, 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.

 

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SIGNATURES

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

 

  GMX RESOURCES INC.
Date: May 10, 2011  

  /s/ James A. Merrill

    James A. Merrill
    Chief Financial Officer

 

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EXHIBIT INDEX

 

        

Incorporated by Reference

    

Exhibit No.

 

Exhibit Description

  

Form

  

SEC File

No.

  

Exhibit

  

Filing Date

  

Filed

Herewith

  3.1(a)   Amended and Restated Certificate of Incorporation of GMX Resources Inc.    SB-2    333-49328    3.1    11/06/2000   
  3.1(b)   Amended Certificate of Incorporation of GMX Resources Inc.    8-K    001-32977    3.1    05/25/2010   
  3.2   Amended and Restated Bylaws of GMX Resources Inc    8-K    001-32977    3.2    11/04/2008   
  3.3   Certificate of Designation of Series A Junior Participating Preferred Stock of GMX Resources Inc.    8-K    000-32325    3.1    05/18/2005   
  3.4   Certificate of Designation of 9.25% Series B Cumulative Preferred Stock    8-A12B    001-32977    4.1    08/08/2006   
  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    05/18/2005   
  4.1(b)   Amendment No. 1 to Rights Agreement dated February 1, 2008    8-A/A    001-32977    4.1    02/21/2008   
  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    02/15/2008   
  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    02/09/2011   
  4.6   Registration Rights Agreement dated February 11, 2008, between GMX Resources Inc. and Jefferies Funding LLC    8-K    001-32977    10.4    02/15/2008   
  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    02/09/2011   
  4.8   Registration Rights Agreement dated February 28, 2011 between GMX Resources Inc. and Retamco Operating, Inc.    8-K    001-32977    10.1    03/02/2011   
10.1(a)   Fifth Amendment and Restated Loan Agreement dated February 2, 2011 among GMX Resources Inc., the Lenders named therein and Capital One, National Association    8-K    001-32977    10.1    02/03/2011   
10.1(b)   First Amendment to Restated Loan Agreement dated February 3, 2011 among GMX Resources Inc., the Lenders named therein and Capital One, National Association    8-K    001-32977    10.6    02/04/2011   
10.1(c)   Second Amendment to Restated Loan Agreement dated as of March 1, 2011 among GMX Resources Inc., the Lenders named therein and Capital One, National Association    8-K    001-32977    10.1    03/24/2011   
10.2   Confirmation of Guaranty Agreement, dated effective February 2, 2011 by Blue Diamond Drilling Co. in favor of Capital One, National Association    8-K    001-32977    10.2    02/03/2011   
10.3   Restated Guaranty Agreement, entered into effective as of July 8, 2010, by Diamond Blue Drilling Co. in favor of Capital One, National Association, as agent, for the benefit of itself, the lenders, the other parties from time to time to the loan agreement, and the other secured parties, guaranteeing the secured liabilities of GMX Resources Inc.    8-K    001-32977    10.3    02/03/2011   

 

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Incorporated by Reference

    

Exhibit No.

  

Exhibit Description

  

Form

  

SEC File

No.

  

Exhibit

  

Filing Date

  

Filed

Herewith

10.4    Confirmation of Guaranty Agreement, dated effective February 2, 2011 by Endeavor Pipeline Inc. in favor of Capital One, National Association    8-K    001-32977    10.4    02/03/2011   
10.5    Restated Guaranty Agreement, entered into effective as of July 8, 2010, by Endeavor Pipeline Inc. in favor of Capital One, National Association, as agent, for the benefit of itself, the lenders, the other parties from time to time to the loan agreement, and the other secured parties, guaranteeing the secured liabilities of GMX Resources Inc.    8-K    001-32977    10.5    02/03/2011   
10.6    Purchase and Sale Agreement (Montana and North Dakota Subject Leases) dated as of January 13, 2011, between GMS Resources Inc. and Retamco Operating, Inc.    10-K    001-32977    10.19    03/11/2011   
10.7    Purchase and Sale Agreement (Wyoming Subject Leases), dated as of January 13, 2011, between GMX Resources Inc. and Retamco Operating, Inc.    10-K    001-32977    10.20    03/11/2011   
10.8    Lease Acquisition Agreement (McKenzie and Dunn County, North Dakota Subject Leases), dated as of January 24, 2011, by and among GMX Resources Inc., Long Properties Trust, Arkon, Bakker, LLC and Reynolds Drilling, Inc.    10-K    001-32977    10.21    03/11/2011   
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          *

 

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