Company Quick10K Filing
Crimson Exploration
10-Q 2013-06-30 Filed 2013-08-08
10-Q 2013-03-31 Filed 2013-05-08
10-K 2012-12-31 Filed 2013-03-15
10-Q 2012-09-30 Filed 2012-11-07
10-Q 2012-06-30 Filed 2012-08-08
10-Q 2012-03-31 Filed 2012-05-09
10-K 2011-12-31 Filed 2012-03-13
10-Q 2011-09-30 Filed 2011-11-09
10-Q 2011-06-30 Filed 2011-08-11
10-Q 2011-03-31 Filed 2011-05-12
10-K 2010-12-31 Filed 2011-03-18
10-Q 2010-09-30 Filed 2010-11-10
10-Q 2010-06-30 Filed 2010-08-05
10-Q 2010-03-31 Filed 2010-05-11
10-K 2009-12-31 Filed 2010-03-16

GULF 10Q Quarterly Report

Part I. Financial Information
Item 1. Financial Statements
Item 2. Management's Discussion and Analysis of Financial
Item 4. Controls and Procedures
Part II. Other Information
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 6. Exhibits
EX-31.1 ex31_1.htm
EX-31.2 ex31_2.htm
EX-32.1 ex32_1.htm
EX-32.2 ex32_2.htm

Crimson Exploration Earnings 2011-06-30

Balance SheetIncome StatementCash Flow
3753002251507502012201220132014
Assets, Equity
40322416802012201220132014
Rev, G Profit, Net Income
3020100-10-202012201220132014
Ops, Inv, Fin

10-Q 1 form10q.htm 6-30-2011-FORM 10Q form10q.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2011

OR

( )  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 001-12108

CRIMSON EXPLORATION INC.
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of incorporation)
 
20-3037840
(IRS Employer Identification No.)
     
717 Texas Avenue, Suite 2900
Houston, Texas
(Address of principal executive offices)
 
77002
(Zip Code)
     

(713) 236-7400
(Registrant’s telephone number, including area code)

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 twelve months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding twelve months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o
Accelerated filer o
Non-accelerated filer o
Smaller reporting company x
   
(Do not check if 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 o  No x

On August 8, 2011, there were 45,113,023 shares outstanding of the registrant’s Common Stock, par value $0.001.

 
1

 

FORM 10-Q

CRIMSON EXPLORATION INC.

FOR THE QUARTER ENDED JUNE 30, 2011


   
 
Page
   
Part I:  Financial Information
 
   
Item 1.    Financial Statements
 
Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010
3
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2011 and 2010
4
Consolidated Statement of Stockholders’ Equity for the Six Months Ended June 30, 2011
5
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010
6
Notes to the Consolidated Financial Statements
7
   
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations
14
   
Item 4.    Controls and Procedures
24
   
Part II: Other Information
 
   
Item 1A. Risk Factors
25
   
Item 2.    Unregistered Sales of Equity Securities and Use Of Proceeds
25
   
Item 6.    Exhibits
25
   
Signatures
28




 
2

 
PART I.     FINANCIAL INFORMATION
ITEM 1.
FINANCIAL STATEMENTS
 
CRIMSON EXPLORATION INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

ASSETS
   
June 30,
   
December 31,
 
   
2011
   
2010
 
   
(unaudited)
       
CURRENT ASSETS
           
    Cash and cash equivalents
  $     $  
    Accounts receivable, net of allowance of $579,143 and $579,143, respectively
    18,258,810       14,225,932  
Prepaid expenses
    202,185       168,766  
Derivative instruments
    3,409,633       6,836,366  
Deferred tax asset, net
    6,880,945       6,331,152  
Total current assets
    28,751,573       27,562,216  
                 
PROPERTY AND EQUIPMENT
               
    Oil and gas properties (successful efforts method of accounting)
    624,803,238       590,248,138  
    Other property and equipment
    3,345,798       3,345,798  
    Accumulated depreciation, depletion and amortization
    (241,138,871 )     (213,547,504 )
Total property and equipment, net
    387,010,165       380,046,432  
                 
NONCURRENT ASSETS
               
    Deposits
    34,743       34,743  
    Debt issuance cost
    1,477,396       2,364,469  
    Deferred tax asset, net
    8,182,597       2,678,966  
Total noncurrent assets
    9,694,736       5,078,178  
                 
TOTAL ASSETS
  $ 425,456,474     $ 412,686,826  
 
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
               
    Accounts payable
  $ 42,661,280     $ 30,795,692  
    Accrued liabilities
    11,762,898       12,799,176  
    Asset retirement obligations
    1,011,633       732,126  
    Derivative instruments
    1,319,417       3,043,078  
Total current liabilities
    56,755,228       47,370,072  
                 
NONCURRENT LIABILITIES
               
    Long-term debt
    185,516,693       172,013,490  
    Asset retirement obligations
    9,073,924       9,101,895  
    Derivative instruments
    460,218        
    Other noncurrent liabilities
    645,721       670,398  
Total noncurrent liabilities
    195,696,556       181,785,783  
                 
Total liabilities
    252,451,784       229,155,855  
                 
COMMITMENTS AND CONTINGENCIES
               
                 
STOCKHOLDERS’ EQUITY
               
Common stock (par value $0.001; 200,000,000 shares authorized; 45,238,933 and 44,952,405 shares issued and 45,110,956 and 44,857,259 shares outstanding, respectively)
    45,239       44,952  
    Additional paid-in capital
    242,472,632       241,488,749  
    Retained deficit
    (68,879,313 )     (57,506,788 )
Treasury stock (at cost, 127,977 and 95,146 shares, respectively)
    (633,868 )     (495,942 )
Total stockholders’ equity
    173,004,690       183,530,971  
                 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 425,456,474     $ 412,686,826  
 
The Notes to the Consolidated Financial Statements are an integral part of these statements.

 
3

 

CRIMSON EXPLORATION INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)

   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2011
   
2010
   
2011
   
2010
 
                         
OPERATING REVENUES
                       
Natural gas sales
  $ 15,538,315     $ 13,542,484     $ 30,263,264     $ 28,016,215  
Crude oil sales
    9,437,066       4,975,157       16,852,709       9,691,852  
Natural gas liquids sales
    4,689,325       2,753,942       10,170,752       6,048,103  
Operating overhead and other income
    162,560       181,360       324,088       306,632  
Total operating revenues
    29,827,266       21,452,943       57,610,813       44,062,802  
                                 
OPERATING EXPENSES
                               
Lease operating expenses
    4,657,344       3,953,646       8,687,922       7,836,497  
Production and ad valorem taxes
    1,958,269       1,477,963       3,838,475       3,180,827  
Exploration expenses
    289,595       187,279       381,209       683,116  
Depreciation, depletion and amortization
    14,385,639       10,514,130       27,866,568       20,937,682  
Impairment and abandonment of oil and gas properties
    3,965,511             9,410,025        
General and administrative
    4,207,331       4,486,375       8,534,819       9,395,695  
Loss on sale of assets
          430,819             430,819  
Total operating expenses
    29,463,689       21,050,212       58,719,018       42,464,636  
                                 
INCOME (LOSS) FROM OPERATIONS
    363,577       402,731       (1,108,205 )     1,598,166  
                                 
OTHER INCOME (EXPENSE)
                               
Interest expense, net of amount capitalized
    (6,247,756 )     (5,245,563 )     (12,982,584 )     (10,602,839 )
Other financing cost
    (471,274 )     (844,927 )     (1,171,870 )     (1,573,030 )
Unrealized (loss) gain on derivative instruments
    2,068,515       (3,917,809 )     (2,163,290 )     1,524,225  
Total other income (expense)
    (4,650,515 )     (10,008,299 )     (16,317,744 )     (10,651,644 )
                                 
LOSS BEFORE INCOME TAXES
    (4,286,938 )     (9,605,568 )     (17,425,949 )     (9,053,478 )
                                 
Income tax benefit
    1,460,375       3,234,718       6,053,424       2,891,443  
                                 
NET LOSS
  $ (2,826,563 )   $ (6,370,850 )   $ (11,372,525 )   $ (6,162,035 )
                                 
NET LOSS PER SHARE
                               
Basic
  $ (0.06 )   $ (0.16 )   $ (0.25 )   $ (0.16 )
Diluted
  $ (0.06 )   $ (0.16 )   $ (0.25 )   $ (0.16 )
                                 
WEIGHTED AVERAGE SHARES OUTSTANDING
                               
Basic
    45,188,542       38,635,725       45,065,402       38,571,300  
Diluted
    45,188,542       38,635,725       45,065,402       38,571,300  









The Notes to the Consolidated Financial Statements are an integral part of these statements.

 
4

 


CRIMSON EXPLORATION INC. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
 
FOR THE SIX MONTHS ENDED JUNE 30, 2011
(UNAUDITED)
 
                                     
   
NUMBER OF SHARES OF
         
ADDITIONAL
               
TOTAL
 
   
COMMON STOCK
   
COMMON STOCK
   
PAID-IN CAPITAL
   
RETAINED EARNINGS
   
TREASURY STOCK
   
STOCKHOLDERS’ EQUITY
 
BALANCE, DECEMBER 31, 2010
    44,857,259     $ 44,952     $ 241,488,749     $ (57,506,788 )   $ (495,942 )   $ 183,530,971  
Current period net loss
                      (11,372,525 )           (11,372,525 )
Share-based compensation
    286,528       287       983,883                     984,170  
Treasury stock
    (32,831 )                       (137,926 )     (137,926 )
BALANCE, JUNE 30, 2011
    45,110,956     $ 45,239     $ 242,472,632     $ (68,879,313 )   $ (633,868 )   $ 173,004,690  
































The Notes to the Consolidated Financial Statements are an integral part of these statements.

 
5

 

CRIMSON EXPLORATION INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 (UNAUDITED)

   
For The Six Months Ended June 30,
 
   
2011
   
2010
 
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net loss
  $ (11,372,525 )   $ (6,162,035 )
Adjustments to reconcile net loss to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    27,866,568       20,937,682  
Asset retirement obligations
    (70,250 )     (139,102 )
Stock compensation expense
    954,258       897,296  
Amortization of financing costs and discounts
    1,436,490       1,374,988  
Deferred income taxes
    (6,053,424 )     (2,923,125 )
Impairment and abandonment of oil and gas properties
    9,410,025       236,457  
Loss on sale of assets
          430,819  
(Gain) loss on derivative instruments
    2,163,290       (1,524,225 )
Changes in operating assets and liabilities:
               
(Increase) decrease in accounts receivable, net
    (4,032,879 )     1,822,789  
Increase in prepaid expenses
    (33,419 )     (7,965 )
    Increase in accounts payable and accrued liabilities
    10,804,633       7,259,238  
Net cash provided by operating activities
    31,072,767       22,202,817  
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Capital expenditures
    (42,978,194 )     (21,755,129 )
Acquisition of oil and gas properties
    (940,345 )      
Sale of assets
          (141,029 )
Net cash used in investing activities
    (43,918,539 )     (21,896,158 )
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Payments on debt
    (72,240,239 )     (39,602,202 )
Proceeds from debt
    85,240,239       39,833,386  
Debt issuance expenditures
    (46,214 )     (466,411 )
Proceeds from stock option exercises
    29,912       16,558  
Purchase of treasury stock
    (137,926 )     (87,990 )
Net cash provided by (used in) financing activities
    12,845,772       (306,659 )
                 
INCREASE IN CASH AND CASH EQUIVALENTS
           
                 
CASH AND CASH EQUIVALENTS,
               
Beginning of period
           
                 
CASH AND CASH EQUIVALENTS,
               
End of period
  $     $  
                 
Cash paid for interest
  $ 13,028,204     $ 13,655,847  
Cash paid for income taxes
  $     $ 95,000  





The Notes to the Consolidated Financial Statements are an integral part of these statements.

 
6

 

CRIMSON EXPLORATION INC. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
 
1.           ORGANIZATION AND NATURE OF OPERATIONS

Crimson Exploration Inc., together with its subsidiaries, (“Crimson”, “we”, “our”, “us”) is an independent energy company engaged in the acquisition, exploitation, exploration and development of natural gas and crude oil properties.  We have historically focused our operations in the onshore U.S. Gulf Coast and South Texas regions, which are generally characterized by high rates of return in known, prolific producing trends.  We have recently expanded our strategic focus to include longer reserve life resource plays that we believe provide significant long-term growth potential in multiple formations.

2.           BASIS OF PRESENTATION

Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“U.S.”) for interim financial information and with the instructions to Form 10-Q and Rule 8-03 of Regulation S-X.  Accordingly, they do not include all of the information and notes required by U.S. generally accepted accounting principles (“GAAP”) for complete annual financial statements.  The accompanying consolidated financial statements at June 30, 2011 (unaudited) and December 31, 2010 and for the three and six months ended June 30, 2011 (unaudited) and 2010 (unaudited) contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations and cash flows for such periods.  Operating results for the three and six months ended June 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011.  These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2010.

The accompanying consolidated financial statements include Crimson Exploration Inc. and its wholly-owned subsidiaries: Crimson Exploration Operating, Inc., formed January 5, 2006, and LTW Pipeline Co., formed April 19, 1999.  All material intercompany transactions and balances are eliminated upon consolidation.  Certain reclassifications have been made to the prior year financial statements to conform to the current year presentation.

New Accounting Standards Adopted in 2011

In January 2010, the Financial Accounting Standards Board (“FASB”)issued Accounting Standards Update No. 2010-06 “Fair Value Measurements and Disclosures (Topic 820) – Improving Disclosures about Fair Value Measurements”.  The guidance requires disclosure of transfers of assets and liabilities between Level 1 and Level 2 in the fair value measurement hierarchy, including the reasons for the transfers and disclosure of major purchases, sales, issuances, and settlements on a gross basis in the reconciliation of the assets and liabilities measured under Level 3 of the fair value measurement hierarchy. The guidance was effective for interim and annual periods beginning after December 15, 2009, except for the Level 3 reconciliation disclosures, which are effective for interim and annual periods beginning after December 15, 2010. We adopted the provisions for the quarter ended March 31, 2010, except for the Level 3 reconciliation disclosures, which we adopted for the quarter ended March 31, 2011. Adopting the disclosure requirements did not have a material impact on our financial position or results of operations. 


 
7

 

3.           USE OF ESTIMATES

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Significant estimates included in the consolidated financial statements are: (1) natural gas, crude oil and natural gas liquids revenues and reserves; (2) depreciation, depletion and amortization; (3) valuation allowances associated with income taxes and accounts receivables; (4) accrued assets and liabilities; (5) stock-based compensation; (6) asset retirement obligations, (7) valuation of derivative instruments, and (8) impairment of oil and gas properties.  Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates.  Actual results could differ from those estimates.

4.
FAIR VALUE MEASUREMENTS

Certain of our assets and liabilities are reported at fair value in our consolidated balance sheets.  The following methods and assumptions were used to estimate the fair values for each class of financial instruments:

Cash and Cash Equivalents, Accounts Receivable and Accounts Payable.  The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.

Derivative Instruments.  Our derivative instruments consist of variable to fixed price commodity swaps, costless collars, put options and interest rate swaps.  The fair value measurement of our unrealized commodity price and interest rate instruments were obtained from financial institutions and were evaluated for accuracy using our hedge agreements and future commodity and interest rate curves.  Differences between management’s calculation and that of the financial institutions were evaluated for reasonableness.  See Note 5 – “Derivative Instruments” for further information.

Impairments.  We review oil and gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices.  We estimate the future cash flows expected in connection with the properties and compare such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable.  The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.  Because these significant fair value inputs are typically not observable, we classify impairments of long-lived assets as a level 3 fair value measure.

Asset Retirement Obligations.  The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties.  The factors used to determine fair value include, but are not limited to, plugging costs and reserve lives.  Because these significant factors are typically not observable, we classify asset retirement obligations as a level 3 fair value measure.

Debt.  The fair value of floating-rate debt is estimated to be equivalent to the carrying amounts because the interest rates paid on such debt are set for periods of three months or less.  See Note 7 - “Debt” for further information.

 
8

 

Accounting guidance has established a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels.  The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).  Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.  There have been no transfers between Level 1, Level 2 or Level 3 during this quarter.

Fair value information for assets and (liabilities) related to our derivative instruments that are measured at fair value was as follows at June 30, 2011:

   
Total
   
Fair Value Measurements Using
 
   
Carrying Value
   
Level 1
   
Level 2
   
Level 3
 
Derivatives
                       
Commodity price contracts
  $ 1,629,998     $     $ 1,629,998     $  

        Fair value information for assets and (liabilities) related to our derivative instruments that are measured at fair value was as follows at December 31, 2010:

   
Total
   
Fair Value Measurements Using
 
   
Carrying Value
   
Level 1
   
Level 2
   
Level 3
 
Derivatives
                       
Commodity price contracts
  $ 5,186,028     $     $ 5,186,028     $  
Interest rate swaps
    (1,392,740 )           (1,392,740 )      
Total
  $ 3,793,288     $     $ 3,793,288     $  

5.           DERIVATIVE INSTRUMENTS

At the end of each reporting period we record on our balance sheet the mark-to-market valuation of our derivative instruments.  We recorded net assets for derivative instruments of $1.6 million and $3.8 million at June 30, 2011 and December 31, 2010, respectively.  As a result of these agreements, we recorded a non-cash unrealized loss, for unsettled contracts, of $2.2 million and a non-cash unrealized gain of $1.5 million for the six months ended June 30, 2011 and 2010, respectively.  The estimated change in fair value of the derivatives is reported in other income (expense) as unrealized gain (loss) on derivative instruments.  The realized gain (loss) on derivative instruments is included in natural gas, crude oil and natural gas liquids sales for our commodity price hedges and as an (increase) decrease in interest expense for our interest rate swaps.  Our final interest rate swap terminated on May 8, 2011.

In the past we have entered into, and may in the future enter into, certain derivative arrangements with respect to portions of our natural gas and crude oil production, to reduce our sensitivity to volatile commodity prices, and with respect to portions of our debt, to reduce our sensitivity to volatile interest rates.  None of our derivative instruments are designated as cash flow or fair value hedges.  We believe that these derivative arrangements, although not free of risk, allow us to achieve a more predictable cash flow and to reduce exposure to commodity price and interest rate fluctuations.  However, derivative arrangements limit the benefit of increases in the prices of natural gas, crude oil and natural gas liquids sales and limit the benefit of decreases in interest rates.  Moreover, our derivative arrangements apply only to a portion of our production and our debt and provide only partial protection against declines in commodity prices and increases in interest rates, respectively.  Such arrangements may expose us to risk of financial loss in certain circumstances.  We continuously reevaluate our hedging programs in light of

 
9

 

changes in production, market conditions, commodity price forecasts, capital spending, interest rate forecasts and debt service requirements.

We use a mix of commodity swaps, put options and costless collars and interest rate swaps to accomplish our hedging strategy.  Derivative assets and liabilities with the same counterparty, subject to contractual terms which provide for net settlement, are reported on a net basis on our consolidated balance sheets.  We have exposure to financial institutions in the form of derivative transactions in connection with our hedges.  These transactions are with counterparties in the financial services industry, and specifically with members of our bank group.  These transactions could expose us to credit risk in the event of default of our counterparties.  In addition, if any lender under our credit agreement is unable to fund their commitment, our liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit agreement.  We believe our counterparty risk is low in part because of the offsetting relationship we have with each of our counterparties provided for in our revolving credit agreement and various hedge contracts.  See Note 4 — “Fair Value Measurements” for further information.

The following derivative contracts were in place at June 30, 2011:
 
Crude Oil
     
Volume/Month
 
Price/Unit
   
Fair Value
 
             Jul 2011-Dec 2011
 
Swap
 
                       3,300 Bbls
 
$70.74
 
$
(517,457
)
             Jul 2011-Dec 2011
 
Collar
 
                       7,000 Bbls
 
$64.50-$69.50
   
(1,156,086
)
             Jul 2011-Sep 2011
 
Swap
 
                          500 Bbls
 
$87.32
   
(13,233
)
             Jul 2011-Dec 2011
 
Swap
 
                       3,100 Bbls
 
$85.65
   
(208,741
)
             Jul 2011-Dec 2011
 
Collar
 
                       5,300 Bbls
 
$90.00-$112.60
   
52,857
 
            Jan 2012-Dec 2012
 
Collar
 
                       4,500 Bbls
 
$90.00-$110.46
   
28,156
 
            Jan 2012-Dec 2012
 
Collar
 
                       5,000 Bbls
 
$85.00-$102.70
   
(333,871
)
            Jan 2012-Dec 2012
 
Collar
 
                       5,100 Bbls
 
$80.00-$107.30
   
(325,274
)
                     
Natural Gas
                   
             Jul 2011-Dec 2011
 
Collar
 
              266,000 Mmbtu
 
$7.32-$8.70
   
4,565,719
 
             Jul 2011-Dec 2011
 
Swap
 
              232,500 Mmbtu
 
$4.39
   
(118,201
)
            Jan 2012-Dec 2012
 
Put
 
              320,000 Mmbtu
 
$5.00
   
(129,428
)
                     
Natural Gas Liquids
                   
             Jul 2011-Dec 2011
(1)
Swap
 
              210,000 Gallons
 
$1.362
   
(214,443
)
       
Commodity price derivative instruments
   
1,629,998
 
                     
Total net fair value of derivative instruments
 
$
1,629,998
 

        (1)  Propane contract


 
10

 

The following table details the effect of derivative contracts on the Consolidated Statements of Operations for the three months and six months ended June 30, 2011 and 2010, respectively:

Contract Type
Location of Gain or (Loss) Recognized in Income
 
Amount of Gain or (Loss) Recognized in Income
 
     
Three months ended June 30,
   
Six months ended June 30,
 
     
2011
   
2010
   
2011
   
2010
 
Commodity price contracts
Operating revenues
  $ 1,075,893     $ 5,925,089     $ 2,905,192     $ 9,908,077  
Interest rate contracts
Interest expense
    (421,423 )     (1,143,135 )     (1,410,764 )     (2,292,777 )
 
Realized gain
  $ 654,470     $ 4,781,954     $ 1,494,428     $ 7,615,300  
                                   
Commodity price contracts
Other income (expense)
  $ 1,648,597     $ (4,939,825 )   $ (3,556,030 )   $ 254,117  
Interest rate contracts
Other income (expense)
    419,918       1,022,016       1,392,740       1,270,108  
 
Unrealized gain (loss)
  $ 2,068,515     $ (3,917,809 )   $ (2,163,290 )   $ 1,524,225  

6.           ASSET RETIREMENT OBLIGATIONS

We estimate the fair values of asset retirement obligations ("AROs") based on historical experience of plug and abandonment costs by field and, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used and inflation rates.

Asset Retirement Obligations Rollforward
 
       
Beginning January 1, 2011 liability
  $ 9,834,021  
Accretion expense
    275,200  
Liabilities incurred
    46,586  
Liabilities settled
    (70,250 )
Revisions
     
Ending June 30, 2011 liability
  $ 10,085,557  

7.           DEBT

We maintain a senior secured revolving credit facility with Wells Fargo Bank, National Association (“Wells Fargo Bank”), as agent, and the lenders party thereto (the “Senior Credit Agreement”) that matures on May 31, 2013.  The borrowing base currently set at $100 million, is based on our current proved crude oil and natural gas reserves, and is subject to semi-annual redeterminations, although our lenders may elect to make one additional unscheduled redetermination between scheduled redetermination dates.  The next borrowing base redetermination under our Senior Credit Agreement is scheduled for November 1, 2011.  As of June 30, 2011, we had $17.0 million outstanding, with availability of $83.0 million, under our Senior Credit Agreement.

We also maintain a second lien credit agreement dated December 27, 2010 with Barclays Bank Plc, as agent, and the lenders party thereto, including an affiliate of OCM GW Holdings, LLC (“Oaktree Holdings”), our largest stockholder (the “Second Lien Credit Agreement”).  The Second Lien Credit Agreement provides for a term loan made to us in a single draw in an aggregate principal amount of $175.0 million that matures on December 27, 2015.  As of June 30, 2011, we had a principal amount of $175.0 million outstanding, with a discount of $6.5 million using the estimated market value interest rate at the time of issuance, for a net reported balance of $168.5 million.

 
11

 

The Senior Credit Agreement and the Second Lien Credit Agreement (the “Credit Agreements”) are secured by liens on substantially all of our assets, as well as security interests in the stock of our subsidiaries.  The liens securing the Second Lien Credit Agreement are junior to those securing the Senior Credit Agreement.  Interest is payable on the Credit Agreements as interim borrowings mature.

The Credit Agreements include usual and customary affirmative and negative covenants for credit facilities of their respective types and sizes, including, among others, limitations on liens, hedging, mergers, asset sales or dispositions, payments of dividends, incurrence of additional indebtedness, certain leases and investments outside of the ordinary course of business, as well as events of default.  The Credit Agreements also contain certain financial covenants.  See Note 9 of our Annual Report on Form 10-K for the year ended December 31, 2010 for a more detailed description of our Credit Agreements and the covenants under the Credit Agreements.  At June 30, 2011, we were in compliance with the aforementioned covenants.

8.           STOCKHOLDERS’ EQUITY

In the six months ended June 30, 2011, 235,413 shares of restricted Common Stock previously issued pursuant to the long-term incentive plan vested, of which 32,831 shares were withheld by us to satisfy the employees’ tax liability resulting from the vesting of these shares, with the remaining shares being distributed to the employees and directors.  During the six months we also had 139,040 unvested shares of restricted Common Stock forfeited due to employee terminations and issued 12,463 shares pursuant to stock option exercises.  Discretionary grants of 366,633 shares of unvested restricted Common Stock were made to our employees during the six months as incentive-based equity compensation under the 2005 Stock Incentive Plan.  We also granted 39,267 shares of restricted Common Stock to three members of our board of directors as compensation pursuant to the director compensation plan, and 7,205 shares of restricted Common Stock to a new employee as part of his total compensation package.

9.           SHARE-BASED COMPENSATION

In February 2011, we initiated an option exchange program (the “Exchange Program”) whereby all outstanding employee stock options previously granted under our 2005 Stock Incentive Plan with an exercise price greater than $5.00 per share, vested and unvested (the “Eligible Options”) could be exchanged for new unvested options.  Due to an annual limitation in the number of options to purchase Common Stock that may be issued in any single year under the 2005 Stock Incentive Plan, Allan D. Keel, our Chief Executive Officer, was limited to exchanging only the portion of Eligible Options held by him that was not in excess of such annual limitation.  The Second Amendment to the Amended and Restated 2005 Stock Incentive Plan, approved by shareholders at the Annual Shareholders’ Meeting on May 17, 2011, increased the annual limitation on option share grants to 750,000 shares thereby allowing the balance of Mr. Keel’s Eligible Options to be exchanged.  The remaining 175,000 Eligible Options that were held by Mr. Keel, which had a weighted average exercise price of $9.70, were exchanged on June 16, 2011 under the same terms as the Exchange Program.  This final transaction completes the Exchange Program.

10.         INCOME TAXES

Income tax benefit for the six months ended June 30, 2011 was $6.1 million compared to income tax benefit of $2.9 million for the six months ended June 30, 2010.  The year-to-date income tax provision is based on our estimate of the effective tax rate expected to be applicable for the full year.  Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, we believe it is more likely than not that we will realize the benefits of these deductible differences net of a tax-adjusted $3.4 million valuation allowance.  The amount of the

 
12

 

deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.

11.         RECENT ACCOUNTING PRONOUNCEMENTS

Accounting Standards Not Yet Adopted

        In May 2011, the FASB issued Accounting Standards Update No. 2011-04 “Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” (“ASU 2011-04”). ASU 2011-04 clarifies application of fair value measurement and disclosure requirements and is effective for interim and annual periods beginning after December 15, 2011, with early application not permitted.  We are currently evaluating the provisions of ASU 2011-04 and assessing the impact, if any, it may have on our financial position and results of operations.

 
13

 

ITEM 2.          MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
                        CONDITION AND RESULTS OF OPERATIONS

Forward-looking Statements

The following discussion should be read in conjunction with the consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management’s discussion and analysis reported on our Annual Report on Form 10-K for the year ended December 31, 2010. Statements in this discussion may be forward-looking.  These forward-looking statements involve risks and uncertainties.

These forward-looking statements include, but are not limited to, statements regarding:

·  
estimates of proved reserve quantities and net present values of those reserves;
·  
reserve potential;
·  
business strategy;
·  
estimates of future commodity prices;
·  
amounts, timing and types of capital expenditures and operating expenses;
·  
expansion and growth of our business and operations;
·  
expansion and development trends of the oil and gas industry;
·  
acquisitions of natural gas and crude oil properties;
·  
production of natural gas and crude oil reserves;
·  
exploration prospects;
·  
wells to be drilled and drilling results;
·  
operating results and working capital;
·  
results of borrowing base redeterminations under our revolving credit facility; and
·  
future methods and types of financing.

We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations.  For a discussion on risk factors affecting our business, see the information in “ITEM 1A. Risk Factors” contained in our Annual Report filed on Form 10-K for the year ended December 31, 2010, as filed with the Securities and Exchange Commission.

Overview

We are an independent energy company engaged in the acquisition, exploitation, exploration and development of natural gas and crude oil properties.  We have historically focused our operations in the onshore U.S. Gulf Coast, South Texas and Colorado regions, which are generally characterized by high rates of return in known, prolific producing trends.  We have recently expanded our strategic focus to include longer reserve life resource plays in East Texas and South Texas that we believe provide significant long-term growth potential in multiple formations.  Our gross revenues are derived from the following sources:

 
1.
Natural gas, crude oil and natural gas liquids sales that are proceeds from the sale of natural gas, crude oil and natural gas liquids production.  This represents over 99% of our gross revenues.

 
2.
Operating overhead and other income that consists primarily of administrative fees received for operating natural gas and crude oil properties for other working interest owners.

 
14

 

Results of Operations

The following is a discussion of our consolidated results of operations, financial condition and capital resources. You should read this discussion in conjunction with our consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q.

Comparative results of operations for the periods indicated are discussed below.

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

Revenues

   
Three months
ended June 30,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Product revenues:
 
(in millions, except percentages)
 
Natural gas sales
  $ 15.5     $ 13.5     $ 2.0       14.8 %
Crude oil sales
    9.4       5.0       4.4       88.0 %
Natural gas liquids sales
    4.7       2.8       1.9       67.9 %
Product revenues
  $ 29.6     $ 21.3     $ 8.3       39.0 %

Natural Gas, Crude Oil and Natural Gas Liquids Sales.  Revenues from the sale of natural gas, crude oil and natural gas liquids, net of the realized effects of our commodity price hedging instruments, were $29.6 million for the second quarter of 2011 compared to $21.3 million for the second quarter of 2010 due to an approximate 62% increase in production, offset, in part, by an approximate 14% decrease in realized commodity prices.

Production
 
   
Three months
ended June 30,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Sales volumes:
                       
Natural gas (Mcf)
    3,268,416       1,961,247       1,307,169       66.6 %
Crude oil (Bbl)
    96,522       58,766       37,756       64.2 %
Natural gas liquids (Bbl)
    97,976       70,637       27,339       38.7 %
Natural gas equivalents (Mcfe)
    4,435,404       2,737,665       1,697,739       62.0 %

        Quarterly production was approximately 4.4 Bcfe for the second quarter of 2011 compared to approximately 2.7 Bcfe for the second quarter of 2010.  On a daily basis, we produced an average of 48,741 Mcfe for the second quarter of 2011 compared to an average of 30,084 Mcfe for the second quarter of 2010, an increase of approximately 62% primarily due to the success of our 2010 and 2011 drilling and workover programs.

 
15

 

Average Sales Prices

   
Three months
ended June 30,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Average sales prices (before hedging):
                       
Natural gas (Mcf)
  $ 4.02     $ 4.12     $ (0.10 )     -2.4 %
Crude oil (Bbl)
    110.59       76.92       33.67       43.8 %
Natural gas liquids (Bbl)
    48.73       38.99       9.74       25.0 %
Natural gas equivalents (Mcfe)
    6.45       5.61       0.84       15.0 %

   
Three months
ended June 30,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Average sales prices (after hedging):
                       
Natural gas (Mcf)
  $ 4.75     $ 6.91     $ (2.16 )     -31.3 %
Crude oil (Bbl)
    97.77       84.66       13.11       15.5 %
Natural gas liquids (Bbl)
    47.86       38.99       8.87       22.7 %
Natural gas equivalents (Mcfe)
    6.69       7.77       (1.08 )     -13.9 %

Natural gas, crude oil and natural gas liquids prices are reported net of the realized effects of our hedging agreements.  We realized gains of $2.4 million on our natural gas hedges and losses of $1.3 million on our crude oil and natural gas liquids hedges in the second quarter of 2011, compared to realized gains of $5.5 million for natural gas hedges and $0.5 million for crude oil hedges in the second quarter of 2010.  The decrease in realized hedging results for 2011 was due to the expiration in 2010 of more favorable natural gas hedges put in place during a higher commodity price environment.

Costs and Expenses

   
Three months ended June 30,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Certain Operating Expenses:
 
(in millions, except percentages)
 
Lease operating expenses
  $ 4.7     $ 4.0     $ 0.7       17.5 %
Production and ad valorem taxes
    2.0       1.5       0.5       33.3 %
Exploration expenses
    0.3       0.2       0.1       50.0 %
General and administrative(1)
    3.8       4.1       (0.3 )     -7.3 %
Operating expenses (cash)
    10.8       9.8       1.0       10.2 %
Depreciation, depletion & amortization
    14.4       10.5       3.9       37.1 %
Share-based compensation(1)
    0.4       0.4             0.0 %
Certain operating expenses
  $ 25.6     $ 20.7     $ 4.9       23.7 %

 
(1)  Total general and administrative costs on the Consolidated Statements of Operations include share-based compensation.


 
16

 


   
Three months ended June 30,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Selected Costs ($ per Mcfe):
 
(in millions, except percentages)
 
Lease operating expenses
  $ 1.05     $ 1.44     $ (0.39 )     -27.1 %
Production and ad valorem taxes
    0.44       0.54       (0.10 )     -18.5 %
Exploration expenses
    0.07       0.07             0.0 %
General and administrative(1)
    0.85       1.50       (0.65 )     -43.3 %
Operating expenses (cash)
    2.41       3.55       (1.14 )     -32.1 %
Depreciation, depletion & amortization
    3.24       3.84       (0.60 )     -15.6 %
Share-based compensation(1)
    0.10       0.14       (0.04 )     -28.6 %
Selected costs
  $ 5.75     $ 7.53     $ (1.78 )     -23.6 %

(1)  Total general and administrative costs on the Consolidated Statements of Operations include share-based compensation.

Lease Operating Expenses.  Lease operating expenses for the second quarter of 2011 were $4.7 million ($1.05 per Mcfe) compared to $4.0 million ($1.44 per Mcfe) in the second quarter of 2010, a slight increase resulting from new wells and fields added due to success in our drilling program.  The decline on a per Mcfe basis is primarily due to the increase in production volumes and continuing the lease operating practices adopted during the downturn of 2009.

Production and Ad Valorem Tax Expenses.  Production and ad valorem tax expenses for the second quarter of 2011 were $2.0 million compared to $1.5 million for the second quarter of 2010, a slight increase due to higher production and field commodity prices in the second quarter of 2011.

Depreciation, Depletion and Amortization (“DD&A”).  DD&A expense for the second quarter of 2011 was $14.4 million compared to $10.5 million for the second quarter of 2010, an increase due to higher production, offset in part by a lower DD&A rate.

Impairment and Abandonment of Oil and Gas Properties.  Non-cash impairment and abandonment of oil and gas properties for the second quarter of 2011 was $4.0 million due to the previously announced impairment of unproved leasehold cost primarily in East Texas.

General and Administrative (“G&A”) Expenses.  Total G&A expenses were $4.2 million ($0.95 per Mcfe) for the second quarter of 2011 compared to $4.5 million ($1.64 per Mcfe) for the second quarter of 2010, a decrease of $0.3 million due to lower legal and other professional fees.  Included in G&A expense is a non-cash stock expense of $0.4 million ($0.10 per Mcfe) and $0.4 million ($0.14 per Mcfe) in the second quarters 2011 and 2010, respectively.

Interest Expense.  Interest expense was $6.2 million ($1.41 per Mcfe) for the second quarter of 2011 compared to $5.2 million ($1.92 per Mcfe) for the second quarter of 2010.  Total interest expense increased primarily due to the refinancing and expanding of our second lien credit agreement in December 2010.  Interest expense capitalized for the second quarters of 2011 and 2010 was approximately $0.1 million and $11,000, respectively.

Other Financing Costs.  Other financing costs were $0.5 million for the second quarter 2011 compared to $0.8 million for the second quarter 2010.  These expenses consist primarily of the amortization of capitalized costs associated with our credit facilities and commitment fees related to the undrawn availability under our revolving credit agreement.

 
17

 

Unrealized Gain on Derivative Instruments.  The non-cash unrealized gain on derivative instruments for the second quarter of 2011 was $2.1 million compared to a non-cash unrealized loss of $3.9 million for the second quarter of 2010.  With the expiration of our interest rate swaps in May 2011, our remaining derivative instruments are strictly commodity based.  The unrealized gain or loss is the change in the mark-to-market exposure under our commodity price hedging contracts.  Unrealized gain or loss will vary period to period, and will be a function of the hedges in place, the strike prices of those hedges and the forward price curve of the commodities and interest rates being hedged.

Income Taxes.  Our net loss before taxes was $4.3 million for the second quarter of 2011 compared to $9.6 million in the second quarter of 2010.  After adjusting for permanent tax differences, we recorded an income tax benefit of $1.5 million for the second quarter of 2011, compared to $3.2 million for the second quarter of 2010.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010
 
Revenues

   
Six months
ended June 30,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Product revenues:
 
(in millions, except percentages)
 
Natural gas sales
  $ 30.3     $ 28.0     $ 2.3       8.2 %
Crude oil sales
    16.9       9.7       7.2       74.2 %
Natural gas liquids sales
    10.2       6.1       4.1       67.2 %
Product revenues
  $ 57.4     $ 43.8     $ 13.6       31.1 %

Natural Gas, Crude Oil and Natural Gas Liquids Sales.  Revenues from the sale of crude oil, natural gas and natural gas liquids, net of the realized effects of our hedging instruments, were $57.4 million for the first six months of 2011 compared to $43.8 million for the first six months of 2010, an increase due primarily to a 56% increase in production, offset in part by a 16% decrease in realized commodity prices.

Production

   
Six months
ended June 30,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Sales volumes:
                       
Natural gas (Mcf)
    6,286,764       4,041,415       2,245,349       55.6 %
Crude oil (Bbl)
    184,251       115,070       69,181       60.1 %
Natural gas liquids (Bbl)
    222,075       141,867       80,208       56.5 %
Natural gas equivalents (Mcfe)
    8,724,720       5,583,037       3,141,683       56.3 %

Production was approximately 8.7 Bcfe for the first six months of 2011 compared to 5.6 Bcfe for the first six months of 2010.  On a daily basis, we produced an average of 48,203 Mcfe in the first six months of 2011 compared to an average of 30,846 Mcfe in the first six months of 2010, an increase of approximately 56% primarily due to the success of our 2010 and 2011 drilling and workover programs.


 
18

 

Average Sales Prices

   
Six months
ended June 30,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Average sales prices (before hedging):
                       
Natural gas (Mcf)
  $ 4.00     $ 4.69     $ (0.69 )     -14.7 %
Crude oil (Bbl)
    102.93       76.78       26.15       34.1 %
Natural gas liquids (Bbl)
    46.22       42.63       3.59       8.4 %
Natural gas equivalents (Mcfe)
    6.23       6.06       0.17       2.8 %

   
Six months
ended June 30,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Average sales prices (after hedging):
                       
Natural gas (Mcf)
  $ 4.81     $ 6.93     $ (2.12 )     -30.6 %
Crude oil (Bbl)
    91.47       84.23       7.24       8.6 %
Natural gas liquids (Bbl)
    45.80       42.63       3.17       7.4 %
Natural gas equivalents (Mcfe)
    6.57       7.84       (1.27 )     -16.2 %

Natural gas, crude oil and natural gas liquids prices are reported net of the realized effect of our hedging agreements.  We realized gains of $5.1 million on our natural gas hedges and losses of $2.2 million on our crude oil hedges in the first six months of 2011, compared to realized gains of $9.0 million on our natural gas hedges and $0.9 million on our crude oil hedges in the first six months of 2010.  The decrease in realized hedging results for 2011 was due to the expiration in 2010 of more favorable natural gas hedges put in place during a higher commodity price environment.

Costs and Expenses

   
Six months ended June 30,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Certain Operating Expenses:
 
(in millions, except percentages)
 
Lease operating expenses
  $ 8.7     $ 7.8     $ 0.9       11.5 %
Production and ad valorem taxes
    3.8       3.2       0.6       18.8 %
Exploration expenses
    0.4       0.7       (0.3 )     -42.9 %
General and administrative(1)
    7.6       8.5       (0.9 )     -10.6 %
Operating expenses
    20.5       20.2       0.3       1.5 %
Depreciation, depletion & amortization
    27.9       20.9       7.0       33.5 %
Share-based compensation
    0.9       0.9             0.0 %
Certain operating expenses
  $ 49.3     $ 42.0     $ 7.3       17.4 %

        (1)  Total general and administrative costs on the Consolidated Statements of Operations include share-based compensation.

 
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Six months ended June 30,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Selected Costs ($ per Mcfe):
 
(in millions, except percentages)
 
Lease operating expenses
  $ 1.00     $ 1.40     $ (0.40 )     -28.6 %
Production and ad valorem taxes
    0.44       0.57       (0.13 )     -22.8 %
Exploration expenses
    0.04       0.12       (0.08 )     -66.7 %
General and administrative(1)
    0.87       1.52       (0.65 )     -42.8 %
Operating expenses
    2.35       3.61       (1.26 )     -34.9 %
Depreciation, depletion & amortization
    3.19       3.75       (0.56 )     -14.9 %
Share-based compensation
    0.11       0.16       (0.05 )     -31.3 %
Selected costs
  $ 5.65     $ 7.52     $ (1.87 )     -24.9 %

(1)  Total general and administrative costs on the Consolidated Statements of Operations include share-based compensation.

Lease Operating Expenses.  Lease operating expenses for the first six months of 2011 were $8.7 million ($1.00 per Mcfe) compared to $7.8 million ($1.40 per Mcfe) in the first six months of 2010, an increase resulting from new wells and fields added due to the success in our drilling program.  The decline on a per Mcfe basis is primarily due to the increase in production volumes and continuing the lease operating practices adopted during the downturn of 2009.
 
Production and Ad Valorem Tax Expenses.  Production and ad valorem tax expenses for the first six months of 2011 were $3.8 million compared to $3.2 million for the first six months of 2010, a slight increase due to higher production and field commodity prices in the first six months of 2011.

Exploration Expenses. Exploration expenses were $0.4 million in the first six months of 2011 compared to $0.7 million for the first six months of 2010.  The decrease in exploration expenses was primarily due to lower G&G costs and unproved abandoned property costs incurred in the first six months of 2011 compared to the first six months of 2010.

Impairment and Abandonment of Oil and Gas Properties.  Non-cash impairment and abandonment of oil and gas properties for the first six months of 2011 was $9.4 million due to the previously announced impairment of unproved leasehold cost primarily in East Texas.

Depreciation, Depletion and Amortization (“DD&A”).  DD&A expense for the first six months of 2011 was $27.9 million compared to $20.9 million for the first six months of 2010, an increase primarily due to higher production, offset in part by a lower DD&A rate.

General and Administrative (“G&A”) Expenses.  Total G&A expenses were $8.5 million ($0.98 per Mcfe) for the first six months of 2011 compared to $9.4 million ($1.68 per Mcfe) for the first six months of 2010, which includes non-cash stock expense of $0.9 million ($0.11 per Mcfe) and $0.9 million ($0.16 per Mcfe) for the first six months of 2011 and 2010, respectively.  G&A expenses decreased primarily due to lower legal and other professional fees.

Loss on Sale of Assets.  The loss on sale of assets during the first six months of 2010 was $0.4 million, due primarily to the final purchase price adjustments on the December 2009 sale of our Southwest Louisiana properties.

 
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Interest Expense.  Interest expense was $13.0 million ($1.49 per Mcfe) for the first six months of 2011 compared to $10.6 million ($1.90 per Mcfe) for the first six months of 2010.  Total interest expense increased primarily due to the refinancing and expanding of our second lien credit agreement in December 2010.  Interest expense capitalized for the first six months of 2011 and 2010 was approximately $0.2 million and $11,000, respectively.

Other Financing Costs.  Other financing costs were $1.2 million for the first six months of 2011 compared with $1.6 million for the first six months of 2010.  These expenses are comprised primarily of the amortization of deferred costs associated with our credit facilities.

Unrealized Loss on Derivative Instruments.  The non-cash unrealized loss for the first six months of 2011 was $2.2 million compared with a non-cash unrealized gain of $1.5 million for the first six months of 2010.  Unrealized gain or loss on derivative instruments is the change in the fair value of our commodity price hedging contracts and our interest rate swaps during the period.  Unrealized gain or loss will vary period to period, and will be a function of hedges in place, the strike prices of those hedges and the forward curve pricing for the commodities and interest rates being hedged.

Income Taxes.  Our net loss before taxes was $17.4 million for the first six months of 2011 compared to $9.1 million for the first six months of 2010.  After adjusting for permanent tax differences, we recorded an income tax benefit of $6.1 million for the first six months of 2011, compared to $2.9 million for the first six months of 2010.

Liquidity and Capital Resources

Our primary cash requirements are for capital expenditures, working capital, operating expenses, acquisitions and principal and interest payments on indebtedness.  Our primary sources of liquidity are cash generated by operations, net of the realized effect of our hedging agreements, and amounts available to be drawn under our revolving credit facility.  To the extent our cash requirements exceed our sources of liquidity, we will be required to fund our cash requirements through other means, such as through debt and equity financing activities or asset monetizations, or the curtailment of capital expenditures.

Liquidity and Cash Flow

Our working capital deficit was $28.0 million as of June 30, 2011, compared to a working capital deficit of $19.8 million as of December 31, 2010.  The following table provides the components and changes in working capital as of June 30, 2011 and December 31, 2010.

 
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June 30, 2011
   
December 31, 2010
   
Change
 
Current assets
                 
Accounts receivable, net (1)
  $ 18.3     $ 14.2     $ 4.1  
Prepaid expenses
    0.2       0.2        
Derivative instruments
    3.4       6.9       (3.5 )
Deferred tax asset, net
    6.9       6.3       0.6  
Total current assets
    28.8       27.6       1.2  
                         
Current liabilities
                       
Accounts payable and accrued liabilities (1)
    54.5       43.6       10.9  
Asset retirement obligations
    1.0       0.7       0.3  
Derivative instruments
    1.3       3.1       (1.8 )
Total current liabilities
    56.8       47.4       9.4  
                         
Working capital (deficit)
  $ (28.0 )   $ (19.8 )   $ (8.2 )

        (1)  Increase in overall capital expenditures and production levels on new, operated properties.

The table below summarizes certain measures of liquidity and capital expenditures, as well as our sources of capital from internal and external sources, for the six months ended June 30, 2011 and 2010, respectively.

   
Six months ended
June 30,
 
   
2011
   
2010
 
Financial Measures
 
(in millions)
 
Net cash provided by operating activities
  $ 31.1     $ 22.2  
Net cash used in investing activities
    (43.9 )     (21.9 )
Net cash provided by (used in) financing activities
    12.8       (0.3 )
Cash and cash equivalents
           

Net cash provided by operating activities was $31.1 million for the six months ended June 30, 2011 compared to $22.2 million for the six months ended June 30, 2010.  During the first six months of 2011, the net cash provided by operating activities, before changes in working capital, increased to $24.3 million, from $13.1 million for the first six months of 2010, primarily due to the increase in production.

Net cash used in investing activities consists primarily of capital expenditures on oil and gas drilling projects and leasehold acquisitions.

Net cash provided by financing activities, which consists primarily of net borrowings/repayments on our revolving credit agreement, was $12.8 million for the six months ended June 30, 2011 compared to net cash used in financing activities of $0.3 million for the six months ended June 30, 2010.

See the Consolidated Statements of Cash Flows for further details.

Capital Resources

We maintain a senior secured revolving credit facility with Wells Fargo Bank, National Association (“Wells Fargo Bank”), as agent, and the lenders party thereto (the “Senior Credit Agreement”) that

 
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matures on May 31, 2013.  The borrowing base currently set at $100 million, is based on our current proved crude oil and natural gas reserves, and is subject to semi-annual redeterminations, although our lenders may elect to make one additional unscheduled redetermination between scheduled redetermination dates.  The next borrowing base redetermination under our Senior Credit Agreement is scheduled for November 1, 2011.  The credit agreement also provides for the issuance of letters-of-credit up to a $5.0 million sub-limit.  As of June 30, 2011, we had $17.0 million outstanding, with availability of $83.0 million under our Senior Credit Agreement.

Advances under our revolving credit agreement are in the form of either base rate loans or LIBOR loans.  The interest rate on the base rate loans fluctuates based upon the higher of the lender’s “prime rate” and the Federal Funds rate.  The interest rate on the LIBOR loans fluctuates based upon the rate at which Eurodollar deposits in the LIBOR market are quoted for the maturity selected.  The applicable margin ranges between 2.75% and 3.50%, for LIBOR loans, and between 1.50% and 2.00%, for base rate loans.  The specific applicable interest margin is determined by, in each case, the percent of the borrowing base utilized at the time of the credit extension.  LIBOR loans of one, two, three and six months may be selected.  The commitment fee payable on the unused portion of our borrowing base is 0.50%, which fee accrues and is payable quarterly in arrears.

We also maintain a second lien credit agreement dated December 27, 2010 with Barclays Bank Plc, as agent, and the lenders party thereto,  including an affiliate of OCM GW Holdings, LLC (“Oaktree Holdings”), our largest stockholder (the “Second Lien Credit Agreement”).  The Second Lien Credit Agreement provides for a term loan, made to us in a single draw, in an aggregate principal amount of $175.0 million and matures on December 27, 2015.  As of June 30, 2011, we had a principal amount of $175.0 million outstanding, with a discount of $6.5 million using the estimated market value interest rate at the time of issuance, for a net reported balance of $168.5 million.

Advances under our new second lien credit agreement are in the form of either base rate loans or LIBOR loans.  The interest rate on the base rate loans fluctuates based upon the greatest of (i) 4.00% per annum, (ii) the “prime rate”, (iii) the Federal Funds Effective Rate plus ½ of 1% and (iv) the LIBOR rate for a one month interest period plus 1.00%.  The applicable margin for base rate loans is 8.50%.  The interest rate on the LIBOR loans fluctuates based upon the higher of (i) 3.0% per annum and (ii) the LIBOR rate per annum.  The applicable margin for LIBOR loans is 9.50%.

Our revolving credit agreement and second lien credit agreement are secured by liens on substantially all of our assets, including the capital stock of our subsidiaries.  The liens securing the obligations under our second lien credit agreement are junior to those under our revolving credit agreement.  Unpaid interest is payable under our credit agreements as interim borrowings mature and renew.

We utilize commodity price hedge instruments to minimize exposure to declining prices on our natural gas, crude oil and natural gas liquids production.  We used a series of swaps, put options and costless collars to accomplish our commodity hedging position.  We currently have 3.8 Bcfe of equivalent production hedged for 2011, consisting of 3.0 Bcf of natural gas hedges, 113.7 MBbl of crude oil hedges and 1.3 million gallons of natural gas liquids (propane) hedges, at average floor prices of $5.95/Mmbtu, $76.48/Bbl and $1.36/gallon, respectively.   We also have 4.9 Bcfe of equivalent production hedged for 2012, consisting of 3.8 Bcf of natural gas hedges and 175.2 MBbl of crude oil hedges at average floor prices of $5.00/Mmbtu and $84.79/Bbl, respectively.

Future Capital Requirements

Our future natural gas, crude oil and natural gas liquids reserves and production, and therefore our cash flow and results of operations, are highly dependent on our success in efficiently developing and

 
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exploiting our current reserves and economically finding or acquiring additional recoverable reserves.  We intend to grow our reserves and production by further exploiting our existing property base through drilling opportunities identified in our resource plays in East and South Texas and in our conventional inventory.  We expect to focus the majority of our drilling activity over the next several years on continued development of our South Texas, East Texas and Colorado resource plays while we continue the development and exploitation of our core legacy properties in the South Texas and Southeast Texas areas.  Due to the current low natural gas price environment, our primary focus for the near-term will be on oil and liquids-rich opportunities.  We anticipate that acquisitions, including those of undeveloped leasehold interests, will continue to play a role in our business strategy as those opportunities arise from time to time.  While there are currently no unannounced agreements for the acquisition of any material businesses or assets, such transactions can be effected quickly and could occur at any time.

We believe that our internally generated cash flow, combined with access to our revolving credit agreement, will be sufficient to meet the liquidity requirements necessary to fund our daily operations and planned capital development and to meet our debt service requirements for the next twelve months.  Our ability to execute on our growth strategy will be determined, in large part, by our cash flow and the availability of debt and equity capital at that time.  Any decision regarding a financing transaction, and our ability to complete such a transaction, will depend on prevailing market conditions and other factors.  Our ability to continue to meet our liquidity requirements and execute on our growth strategy can be impacted by economic conditions outside of our control, such as commodity price volatility, which could, among other things, lead to a decline in the borrowing base under our revolving credit agreement in connection with a borrowing base redetermination.  In such case, we may be required to seek other sources of capital earlier than anticipated.  Restrictions in our credit agreements may impair our ability to access other sources of capital, and access to additional capital may not be available on terms acceptable to us or at all.  See Item 1A. “Risk Factors” and Item 7.  “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in our Annual Report on Form 10-K for the year ended December 31, 2010.

Recent Accounting Pronouncements

In May 2011, the FASB issued Accounting Standards Update No. 2011-04 “Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” (“ASU 2011-04”). ASU 2011-04 clarifies application of fair value measurement and disclosure requirements and is effective for interim and annual periods beginning after December 15, 2011, with early application not permitted.  We are currently evaluating the provisions of ASU 2011-04 and assessing the impact, if any, it may have on our financial position and results of operations.

ITEM 4.          CONTROLS AND PROCEDURES

Our President and Chief Executive Officer and our Chief Financial Officer have concluded, based on their evaluation as of the end of the period covered by this Form 10-Q, that our disclosure controls and procedures, as defined under Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, are effective to ensure that information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that our disclosure controls and procedures are effective to ensure that information we are required to disclose in such reports is accumulated and communicated to management, including our President and Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

During the period covered by this report, there has been no change to our internal controls over financial reporting that materially affected, or is reasonably likely to materially affect, these controls.

 
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PART II.     OTHER INFORMATION

ITEM 1A.
RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010, which could materially affect our business, financial condition or future results.  The risks described in this report and in our previous filings with the Securities and Exchange Commission are not the only risks facing our company.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

We withheld the following shares of Crimson Common Stock from employee stock distributions to satisfy tax withholding obligations related to restricted stock which vested during the second quarter of 2011.  These shares may be deemed to be “issuer purchases” of shares that are required to be disclosed pursuant to this item.

Period
 
Total Number of Shares Purchased (1)
   
Average price Paid Per Share
   
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)
   
Maximum Number (or Approximate Dollar Value) of Shares That May Be Purchased Under the Plan or Programs
 
May 1-31, 2011
    7,881     $ 3.90       7,881                    (1)  
June 1-30, 2011
    3,716     $ 3.92       3,716                    (1)  
Total
    11,597               11,597          

(1)  Shares were withheld from employees to satisfy certain tax withholding obligations due in connection with grants of stock under our 2005 Stock Incentive Plan.  The 2005 Stock Incentive Plan provides for the withholding of shares to satisfy tax obligations.

ITEM 6.
EXHIBITS

Number
 
Description
 
     
3.1
 
 Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on July 5, 2005)
     
3.2
 
 Certificate of Amendment of Certificate of Incorporation (incorporated by reference to Appendix A to the Company’s Definitive Information Statement on Schedule 14C filed on August 18, 2006)
     
3.3
 
 Certificate of Designation, Preferences and Rights of Series I Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 29, 2010)


 
25

 


Number
 
Description
 
     
3.4
 
 Bylaws of Crimson Exploration Inc. (incorporated by reference to Exhibit 3.7 to the Company’s Current Report on Form 8-K filed on July 5, 2005)
     
4.1
 
 Form of Common Stock Certificate (incorporated by reference to Exhibit 3.7 to the Company’s Current Report on Form 8-K filed on July 5, 2005)
     
4.2
 
 Shareholders Rights Agreement between GulfWest Energy Inc. and OCM GW Holdings, LLC dated February 28, 2005 (incorporated by reference to Exhibit 99(e) of the Schedule 13D, Reg. No. 005-54301, filed on March 10, 2005)
     
4.3
 
 Waiver, Consent and First Amendment to the Shareholders Rights Agreement, dated as of December 7, 2009, between Crimson Exploration Inc. and OCM GW Holdings, LLC (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on December 10, 2009)
     
4.4
 
 Termination Agreement, dated as of December 7, 2009, between Crimson Exploration Inc. and OCM GW Holdings, LLC (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on December 10, 2009)
     
#10.1
 
First Amendment to the Amended and Restated 2005 Stock Incentive Plan (Incorporated by reference to Exhibit B to the Company’s definitive proxy statement on Schedule 14A filed on April 13, 2011)
     
#10.2
 
Second Amendment to the Amended and Restated 2005 Stock Incentive Plan (Incorporated by reference to Exhibit C to the Company’s definitive proxy statement on Schedule 14A filed on April 13, 2011)
     
#10.3
 
Amended and Restated Employment Agreement between Allan D. Keel and Crimson Exploration Inc., dated June 29, 2011 (incorporated by reference to Exhibit 10.1 to the Company’s Report on Form 8-K filed on July 12, 2011)
     
#10.4
 
Amended and Restated Employment Agreement between E. Joseph Grady and Crimson Exploration Inc., dated June 29, 2011 (incorporated by reference to Exhibit 10.2 to the Company’s Report on Form 8-K filed on July 12, 2011)
     
#10.5
 
Amended and Restated Employment Agreement between Thomas H. Atkins and Crimson Exploration Inc., dated June 29, 2011 (incorporated by reference to Exhibit 10.3 to the Company’s Report on Form 8-K filed on July 12, 2011)
     
#10.6
 
Amended and Restated Employment Agreement between Jay S. Mengle and Crimson Exploration Inc., dated June 29, 2011 (incorporated by reference to Exhibit 10.4 to the Company’s Report on Form 8-K filed on July 12, 2011)


 
26

 

 
Number
 
Description
 
*31.1
 
Certification of Chief Executive Officer pursuant to Exchange Rule13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
     
*31.2
 
Certification of Chief Financial Officer pursuant to Exchange Rule 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
     
**32.1
 
Certification of Chief Executive Officer pursuant to 18.U.S.C Section 1350 pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
     
**32.2
 
Certification of Chief Financial Officer pursuant to 18.U.S.C Section 1350 pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
     
*101.INS
 
XBRL Instance Document
     
*101.SCH
 
XBRL Schema Document
       
 *101.CAL    XBRL Calculation Linkbase Document
     
 *101.LAB    XBRL Labels Linkbase Document
     
 *101.PRE    XBRL Presentation Linkbase Document
     
 *101.DEF    XBRL Definition Linkbase Document
     
     *Filed herewith
     **Furnished herewith
     #Management contract or compensatory plan or arrangement
 
 
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SIGNATURES

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

CRIMSON EXPLORATION INC.
(Registrant)



Date:
August 11, 2011
By:
/s/ Allan D. Keel
     
Allan D. Keel
     
President and Chief Executive Officer
       
Date:
August 11, 2011
By:
/s/ E. Joseph Grady
     
E. Joseph Grady
     
Senior Vice President and Chief Financial Officer


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