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 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Part II. Other Information
Item 1. Legal Proceedings
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 2013-06-30

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

10-Q 1 form10q.htm CRIMSON FORM 10Q - Q2 2013 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, 2013

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 x
Non-accelerated filer o
Smaller reporting company o
   
(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 July 30, 2013, there were 46,671,986 shares outstanding of the registrant’s Common Stock, par value $0.001.

 
 

 

FORM 10-Q

CRIMSON EXPLORATION INC.

FOR THE QUARTER ENDED JUNE 30, 2013


Table of Contents
 
Page
   
Part I:      Financial Information
 
   
                Item 1.        Financial Statements
 
Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012
3
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2013 and 2012
4
Consolidated Statement of Stockholders’ Equity for the Six Months Ended June 30, 2013
5
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012
6
Notes to the Consolidated Financial Statements
7
   
Item 2.        Management’s Discussion and Analysis of Financial Condition and Results of Operations
18
   
Item 3.        Quantitative and Qualitative Disclosures about Market Risk
29
   
Item 4.        Controls and Procedures
30
   
Part II:    Other Information
 
   
Item 1.        Legal Proceedings
31
   
Item 1A.     Risk Factors
31
   
Item 2.        Unregistered Sales of Equity Securities and Use Of Proceeds
34
   
Item 6.        Exhibits
34
   
Signatures
37




 
2

 

PART I.     FINANCIAL INFORMATION

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

ASSETS
   
June 30,
   
December 31,
 
   
2013
   
2012
 
   
(unaudited)
       
CURRENT ASSETS
           
    Cash and cash equivalents
  $     $  
    Accounts receivable, net of allowance of $559,878 and $525,556 respectively
    13,924,071       11,726,078  
Prepaid expenses
    791,323       844,495  
Derivative instruments
    2,084,643       1,892,744  
Deferred tax asset, net
    10,807,366       10,361,157  
Total current assets
    27,607,403       24,824,474  
                 
PROPERTY AND EQUIPMENT
               
    Oil and gas properties (successful efforts method of accounting)
    768,895,637       740,070,145  
    Other property and equipment
    3,010,173       3,061,635  
    Accumulated depreciation, depletion and amortization
    (473,460,678 )     (442,304,300 )
Total property and equipment, net
    298,445,132       300,827,480  
                 
NONCURRENT ASSETS
               
    Deposits
    34,743       34,743  
    Debt issuance cost
    864,379       1,056,272  
    Derivative instruments
    635,593       67,261  
    Deferred tax asset, net
    43,610,739       41,810,159  
Total noncurrent assets
    45,145,454       42,968,435  
                 
TOTAL ASSETS
  $ 371,197,989     $ 368,620,389  
 
  LIABILITIES
CURRENT LIABILITIES
               
    Accounts payable
  $ 39,288,738     $ 31,127,671  
    Accrued liabilities
    13,557,426       6,680,843  
    Asset retirement obligations
    1,352,209       876,774  
Total current liabilities
    54,198,373       38,685,288  
                 
NONCURRENT LIABILITIES
               
    Long-term debt
    229,926,282       239,368,865  
    Asset retirement obligations
    9,755,352       10,152,432  
    Other noncurrent liabilities
    547,010       571,687  
Total noncurrent liabilities
    240,228,644       250,092,984  
                 
Total liabilities
    294,427,017       288,778,272  
                 
COMMITMENTS AND CONTINGENCIES
               
                 
STOCKHOLDERS’ EQUITY
               
Common stock (par value $0.001; 200,000,000 shares authorized; 46,951,397 and 46,259,009 shares issued and 46,671,986 and 46,063,822 shares outstanding, respectively)
    46,951       46,259  
    Additional paid-in capital
    247,397,834       246,007,941  
    Retained deficit
    (169,536,605 )     (165,343,525 )
Treasury stock (at cost, 279,411 and 195,187 shares, respectively)
    (1,137,208 )     (868,558 )
Total stockholders’ equity
    76,770,972       79,842,117  
                 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 371,197,989     $ 368,620,389  
 

 
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,
 
   
2013
   
2012
   
2013
   
2012
 
                         
OPERATING REVENUES
                       
Crude oil sales
  $ 26,415,041     $ 21,505,766     $ 42,508,437     $ 38,398,380  
Natural gas sales
    7,326,514       6,051,551       13,329,189       13,120,665  
Natural gas liquids sales
    3,056,063       2,966,694       5,054,926       5,691,545  
Total operating revenues
    36,797,618       30,524,011       60,892,552       57,210,590  
                                 
OPERATING EXPENSES
                               
Lease operating expenses
    3,294,735       3,603,046       6,556,862       8,240,431  
Production and ad valorem taxes
    2,362,788       (2,488,997 )     4,051,530       (1,080,256 )
Exploration expenses
    185,649       48,895       303,130       349,591  
Depreciation, depletion and amortization
    18,612,302       14,675,882       31,452,022       29,137,944  
Impairment of oil and gas properties
    827,677       806,067       1,645,415       1,482,541  
General and administrative
    6,849,167       4,525,720       11,163,501       9,297,177  
Gain on sale of assets
    (4,975 )           (11,359 )     (8,900 )
Total operating expenses
    32,127,343       21,170,613       55,161,101       47,418,528  
                                 
INCOME FROM OPERATIONS
    4,670,275       9,353,398       5,731,451       9,792,062  
                                 
OTHER INCOME (EXPENSE)
                               
Interest expense
    (6,325,864 )     (6,212,806 )     (12,609,601 )     (12,457,988 )
Other income and financing cost
    (131,814 )     (103,544 )     (251,216 )     (346,287 )
Unrealized gain on derivative instruments
    2,643,221       3,037,733       760,231       2,512,100  
Total other income (expense)
    (3,814,457 )     (3,278,617 )     (12,100,586 )     (10,292,175 )
                                 
INCOME (LOSS) BEFORE INCOME TAXES
    855,818       6,074,781       (6,369,135 )     (500,113 )
                                 
Income tax (expense) benefit
    (317,499 )     (2,163,962 )     2,176,055       11,847  
                                 
NET INCOME (LOSS)
  $ 538,319     $ 3,910,819     $ (4,193,080 )   $ (488,266 )
                                 
NET INCOME (LOSS) PER SHARE
                               
Basic
  $ 0.01     $ 0.09     $ (0.09 )   $ (0.01 )
Diluted
  $ 0.01     $ 0.09     $ (0.09 )   $ (0.01 )
                                 
WEIGHTED AVERAGE SHARES OUTSTANDING
                               
Basic
    44,681,434       44,134,330       44,536,281       44,055,639  
Diluted
    44,995,267       44,992,883       44,536,281       44,484,917  









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, 2013
(UNAUDITED)
 
                                     
   
NUMBER OF SHARES OF
         
ADDITIONAL
               
TOTAL
 
   
COMMON STOCK
   
COMMON STOCK
   
PAID-IN CAPITAL
   
RETAINED DEFICIT
   
TREASURY STOCK
   
STOCKHOLDERS’ EQUITY
 
BALANCE, DECEMBER 31, 2012
    46,063,822     $ 46,259     $ 246,007,941     $ (165,343,525 )   $ (868,558 )   $ 79,842,117  
Current period net loss
                      (4,193,080 )           (4,193,080 )
Share-based compensation
    692,388       692       1,389,893                   1,390,585  
Treasury stock
    (84,224 )                       (268,650 )     (268,650 )
BALANCE, JUNE 30, 2013
    46,671,986     $ 46,951     $ 247,397,834     $ (169,536,605 )   $ (1,137,208 )   $ 76,770,972  



































The Notes to the Consolidated Financial Statements are an integral part of this statement.

 
5

 

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

   
For The Six Months Ended June 30,
 
   
2013
   
2012
 
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net loss
  $ (4,193,080 )   $ (488,266 )
Adjustments to reconcile net loss to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    31,452,022       29,137,944  
Asset retirement obligations
    (187,974 )     (39,435 )
Stock compensation expense
    1,350,276       1,172,022  
Amortization of financing costs and discounts
    851,471       772,201  
Deferred income taxes
    (2,246,789 )     (11,847 )
Impairment and abandonment of oil and gas properties
    1,645,415       1,482,541  
Gain on sale of assets
    (11,359 )     (8,900 )
Unrealized gain on derivative instruments
    (760,231 )     (2,512,100 )
Changes in operating assets and liabilities:
               
(Increase) decrease in accounts receivable, net
    (2,197,993 )     1,623,709  
Decrease (increase) in prepaid expenses
    53,172       (243,442 )
Increase (decrease) in accounts payable and accrued liabilities
    15,012,973       (7,627,594 )
Net cash provided by operating activities
    40,767,903       23,256,833  
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Capital expenditures
    (30,448,760 )     (60,288,459 )
Proceeds from sale of assets
    11,359       400,900  
Net cash used in investing activities
    (30,437,401 )     (59,887,559 )
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Payments on debt
    (87,773,331 )     (108,273,279 )
Proceeds from debt
    77,671,170       145,349,665  
Debt issuance expenditures
          (304,225 )
Proceeds from issuance of common stock
    40,309       6,953  
Purchase of treasury stock
    (268,650 )     (148,388 )
Net cash provided by (used in) financing activities
    (10,330,502 )     36,630,726  
                 
INCREASE IN CASH AND CASH EQUIVALENTS
           
                 
CASH AND CASH EQUIVALENTS,
               
Beginning of period
           
                 
CASH AND CASH EQUIVALENTS,
               
End of period
  $     $  
                 
Cash paid for interest
  $ 11,834,325     $ 11,850,456  
Cash paid for income taxes
  $ 70,734     $  






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 exploitation, exploration, development and acquisition of crude oil and natural gas properties.  We have historically focused our operations in the onshore U.S. Gulf Coast, Texas and Colorado regions, which are generally characterized by high rates of return in known, prolific producing trends.  We have 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 from multiple formations.  Our operating revenues are derived from crude oil, natural gas and natural gas liquids sales that are proceeds from the sale of crude oil, natural gas and natural gas liquids production and net realizations on associated commodity derivative instruments.

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, 2013 (unaudited) and December 31, 2012 and for the three and six months ended June 30, 2013 (unaudited) and 2012 (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, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013.

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, 2012.

The accompanying consolidated financial statements include Crimson Exploration Inc. and its wholly-owned subsidiaries: Crimson Exploration Operating, Inc. and LTW Pipeline Co. All material intercompany transactions and balances are eliminated upon consolidation.

3.           CONTANGO MERGER
 
        On April 29, 2013, Crimson entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Contango Oil & Gas Company, a Delaware corporation (“Contango”), and Contango Acquisition, Inc., a Delaware corporation and a direct, wholly-owned subsidiary of Contango (“Merger Sub”), providing for a strategic business combination of Crimson and Contango.  Upon the terms and conditions set forth in the Merger Agreement, Merger Sub will be merged with and into Crimson (the “Merger”), with Crimson continuing as a wholly-owned subsidiary of Contango.  The Merger Agreement was approved by each of the board of directors of Crimson and Contango on April 29, 2013.

        Subject to the terms and conditions of the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each share of Crimson common stock, par value $0.001 per share, issued and

 
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outstanding will be converted into the right to receive 0.08288 shares of common stock, par value $0.04 per share, of Contango (“Contango Common Stock”) or, in the case of fractional shares, cash (without interest) in an amount equal to the product of (i) such fractional part of a share of Contango Common Stock multiplied by (ii) the closing price for a share of Contango Common Stock as reported on the New York Stock Exchange on the first trading day following the date on which the Effective Time occurs (the “Merger Consideration”).

        Crimson and Contango have each made certain representations and warranties and agreed to certain covenants in the Merger Agreement. Each of Contango and Crimson has agreed, among other things: (i) subject to certain exceptions, to conduct its respective business in the ordinary course during the period between the execution of the Merger Agreement and the Effective Time; (ii) not to solicit alternative business combination transactions during such period; and (iii) subject to certain exceptions, not to engage in discussions or negotiations regarding any alternative business combination transactions during such period.

        The closing of the Merger is subject to the satisfaction or waiver of certain customary conditions, including, among others, (i) the adoption of the Merger Agreement by Crimson’s stockholders; (ii) the approval by Contango’s stockholders of the issuance of Contango Common Stock in the Merger to Crimson’s stockholders (the “Share Issuance”); (iii) the registration statement on Form S-4 used to register the Contango Common Stock to be issued in the Merger being declared effective by the Securities and Exchange Commission (the “SEC”); (iv) the approval for listing on the New York Stock Exchange of the Contango Common Stock to be issued in the Merger; (v) subject to specified materiality standards, the accuracy of the representations and warranties of, and the performance of all covenants by, the parties; (vi) the absence of a material adverse effect with respect to each of Crimson and Contango; and (vii) the delivery of tax opinions that the Merger will be treated as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code.

        The Merger Agreement contains certain termination rights for both Crimson and Contango, including, among others, if (i) the Merger is not consummated on or before October 31, 2013; (ii) the requisite approval of the stockholders of either Crimson or Contango is not obtained; and (iii) the other party breaches a representation, warranty or covenant, and such breach results in the failure of closing conditions to be satisfied.  The Merger Agreement further provides that for the payment of a termination fee upon the termination of the Merger Agreement under specified circumstances, including termination by Contango or Crimson as a result of (1) an adverse change in the recommendation of the other party’s board of directors or (2) a third-party’s “superior proposal.”  The termination fee is $7.0 million (if payable by Crimson) and $28.0 million (if payable by Contango).  The Merger Agreement also provides that Crimson or Contango may be required to pay the other party $4.5 million for expense reimbursement if such party’s stockholder approval is not obtained.

        Contango and Crimson currently expect the closing of the Merger to occur in September or October of 2013.  However, as the Merger is subject to the satisfaction or waiver of other conditions described in the Merger Agreement, it is possible that factors outside the control of Contango and Crimson could result in the Merger being completed at an earlier time, a later time or not at all.

        Simultaneously with the execution of the Merger Agreement, Crimson entered into a support agreement with (a) each of Joseph J. Romano, Sergio Castro, Yaroslava Makalskaya and Brad Juneau (each, a “Contango Stockholder”) and (b) Mr. Romano in his capacity as Temporary Administrator of the Estate of Kenneth R. Peak (each such support agreement, a “Contango Support Agreement”).  The Contango Support Agreements provide that, upon the terms and conditions set forth therein, each Contango Stockholder will vote all shares of Contango Common Stock beneficially owned by such Contango Stockholder (i) in favor of the Share Issuance; and (ii) against certain other specified alternative

 
8

 


transactions or actions.  Each Contango Support Agreement terminates upon the earliest to occur of (1) the termination of the Merger Agreement in accordance with its terms and (2) the Effective Time.

        Additionally, simultaneously with the execution of the Merger Agreement, Contango entered into a support agreement (each, a “Crimson Support Agreement,” and, together with the Contango Support Agreements, the “Support Agreements”) with each of Allan D. Keel, E. Joseph Grady, Thomas H. Atkins, A. Carl Isaac, Jay S. Mengle, John A. Thomas, OCM GW Holdings, LLC, and OCM Crimson Holdings, LLC (each, a “Crimson Stockholder”).  The Crimson Support Agreements provide that, upon the terms and conditions set forth therein, each Crimson Stockholder will vote all shares of Crimson Common Stock beneficially owned by such Crimson Stockholder (i) in favor of the approval of the Merger Agreement, the Merger and any other matter that is required to be approved by the stockholders of Crimson in order to effect the Merger; and (ii) against certain other specified alternative transactions or actions.  Each Crimson Support Agreement terminates upon the earliest to occur of (1) the termination of the Merger Agreement in accordance with its terms; (2) the Effective Time; and (3) any reduction of the Merger Consideration or change in the form of the Merger Consideration.

        For additional information about the Merger, please see our Current Report on Form 8-K, filed with the SEC on April 30, 2013, and the Merger Agreement, which is attached as Exhibit 2.1 thereto and other filings with the SEC related to the Merger.

4.           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) crude oil, natural gas 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.

5.
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 typically consist from time to time 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 reviewed by management 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 6 — “Derivative Instruments” for further information.

 
9

 


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 measurement.  See Note 7 — “Oil and Gas Properties” for further information.

Asset Retirement Obligations.  The initial measurement of asset retirement obligations ("AROs") 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 measurement.  See Note 8 — “Asset Retirement Obligations” for further information.

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 9 — “Debt” for further information.

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 related to our derivative instruments measured at fair value on a recurring basis was as follows at June 30, 2013:

   
Total
   
Fair Value Measurements Using
 
   
Carrying Value
   
Level 1
   
Level 2
   
Level 3
 
Derivatives
                       
Commodity price contracts - assets
  $ 2,720,236     $     $ 2,720,236     $  

At June 30, 2013, we did not measure assets or liabilities at fair value on a non-recurring basis.


Fair value information related to our derivative instruments measured at fair value on a recurring basis was as follows at December 31, 2012:

   
Total
   
Fair Value Measurements Using
 
   
Carrying Value
   
Level 1
   
Level 2
   
Level 3
 
Derivatives
                       
Commodity price contracts - assets
  $ 1,960,005     $     $ 1,960,005     $  


 
10

 


6.           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 $2.7 million and $2.0 million at June 30, 2013 and December 31, 2012, respectively.  As a result of these agreements, we recorded non-cash unrealized gains for unsettled contracts of $0.8 million and $2.5 million for the six months ended June 30, 2013 and 2012, 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 crude oil, natural gas and natural gas liquids sales.

In the past we have entered into, and may in the future enter into, certain derivative arrangements with respect to portions of our crude oil and natural gas 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 crude oil, natural gas 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 provide only partial protection against declines in commodity prices.  Such arrangements may expose us to risk of financial loss in certain circumstances.  We continuously reevaluate our hedging programs in light of changes in production, market conditions, commodity price forecasts, capital spending, interest rate forecasts and debt service requirements.

We typically use a mix of commodity swaps and costless collars 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.  We believe our counterparty risk is low in part because of the offsetting relationship we have with each of our counterparties as provided for in our revolving credit agreement and various hedge contracts.  See Note 5 — “Fair Value Measurements” for further information.


 
11

 


The following derivative contracts were in place at June 30, 2013:

Crude Oil
     
Volume/Month
   
Price/Unit
   
Fair Value
 
Jul 2013-Dec 2013
 
Swap
 
14,000 Bbls
 
$
101.25 (1)
 
$
513,926
 
Jul 2013-Dec 2013
 
Swap
 
9,000 Bbls
   
109.13 (2)
   
444,279
 
Jul 2013-Dec 2013
 
Swap
 
6,000 Bbls
   
107.10 (2)
   
223,175
 
Jul 2013-Sep 2013
 
Swap
 
6,000 Bbls
   
103.47 (2)
   
35,530
 
Oct 2013-Dec 2013
 
Swap
 
3,000 Bbls
   
102.30 (2)
   
18,245
 
Jan 2014-Dec 2014
 
Swap
 
7,500 Bbls
   
102.10 (2)
   
394,075
 
Jan 2014-Jun 2014
 
Swap
 
2,000 Bbls
   
108.07 (2)
   
111,523
 
Jan 2014-Dec 2014
 
Swap
 
6,000 Bbls
   
106.40 (2)
   
622,903
 
                       
Natural Gas
                     
Jul 2013-Dec 2013
 
Collar
 
75,000 Mmbtu
   
Put $3.00-$4.25 Call (3)
   
(14,454
)
Jul 2013-Dec 2013
 
Collar
 
75,000 Mmbtu
   
Put $3.25-$4.00 Call (3)
   
(15,256
)
Jul 2013-Dec 2013
 
Collar
 
35,000 Mmbtu
   
Put $3.75-$4.21 Call (3)
   
40,606
 
Jul 2013-Dec 2013
 
Swap
 
70,000 Mmbtu
   
$4.02 (3)
   
153,979
 
Jul 2013-Dec 2014
 
Collar
 
42,500 Mmbtu
   
Put $3.75-$4.60 Call (3)
   
120,855
 
Jul 2013-Dec 2014
 
Collar
 
42,500 Mmbtu
   
Put $3.50-$5.00 Call (3)
   
70,850
 
                       
 
Total net fair value of derivative instruments
 
$
2,720,236
 

(1)  
Commodity derivative based on West Texas Intermediate crude oil
(2)  
Commodity derivative based on Brent crude oil
(3)  
Commodity derivatives based on Henry Hub NYMEX natural gas prices

In July 2013, we entered into another crude oil swap for 40,000 Bbl/month for the remainder of the 2013 calendar year at $99.00 per barrel (WTI).  This new hedge is part of our ongoing hedging strategy.

The following table details the effect of derivative contracts on the Consolidated Statements of Operations for the three and six months ended June 30, 2013 and 2012, 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,
 
       
2013
   
2012
   
2013
   
2012
 
Crude oil contracts
 
Crude oil sales
  $ 603,205     $ 586,360     $ 395,936     $ 424,673  
Natural gas contracts
 
Natural gas sales
    (82,495 )     1,990,720       61,830       3,526,180  
   
Realized gain
  $ 520,710     $ 2,577,080     $ 457,766     $ 3,950,853  
                                     
Crude oil contracts
 
Unrealized gain on derivative instruments
  $ 1,799,880     $ 5,724,945     $ 1,650,927     $ 4,192,815  
Natural gas contracts
 
Unrealized (loss) gain on derivative instruments
    843,341       (2,687,212 )     (890,696 )     (1,680,715 )
   
Unrealized gain
  $ 2,643,221     $ 3,037,733     $ 760,231     $ 2,512,100  


 
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Balance Sheet Presentation

Our derivatives are presented on a net basis in derivative instruments on the Consolidated Balance Sheets.  The following summarizes the fair value of derivatives outstanding on a gross and net basis:

   
June 30, 2013
 
   
Gross
   
Netting (1)
   
Total
 
Assets:
                 
Commodity derivatives
  $ 2,749,946     $ (29,710 )   $ 2,720,236  
Liabilities:
                       
Commodity derivatives
    29,710       (29,710 )      

   
December 31, 2012
 
   
Gross
   
Netting (1)
   
Total
 
Assets:
                 
Commodity derivatives
  $ 2,206,705     $ (246,700 )   $ 1,960,005  
Liabilities:
                       
Commodity derivatives
    246,700       (246,700 )      

(1)  
Represents counterparty netting under agreements governing such derivatives

7.           OIL AND GAS PROPERTIES

The following table sets forth the composition of impairment expenses:

   
Three months ended
   
Six months ended
 
   
June 30,
   
June 30,
 
   
2013
   
2012
   
2013
   
2012
 
Impairments of unproved properties
    827,677       806,067       1,645,415       1,482,541  
    $ 827,677     $ 806,067     $ 1,645,415     $ 1,482,541  

2013 Asset Impairments. Non-cash impairments of unproved properties are related to individually insignificant acreage.  There were no impairments or abandonments of proved properties for the three and six months ended June 30, 2013.

2012 Asset Impairments. Non-cash impairments of unproved properties are related to individually insignificant acreage.  There were no impairments or abandonments of proved properties for the three and six months ended June 30, 2012.


 
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8.           ASSET RETIREMENT OBLIGATIONS

We estimate the fair values of 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.  The following table sets forth the composition of asset retirement obligations rollforward:

Beginning January 1, 2013 liability
  $ 11,029,206  
Accretion expense
    244,182  
Liabilities incurred
    16,727  
Liabilities settled
    (187,976 )
Revisions
    5,422  
Ending June 30, 2013 liability
  $ 11,107,561  

9.           DEBT

We maintain a senior secured revolving credit facility with Wells Fargo Bank, National Association (“Wells Fargo Bank”), as agent, and the lender parties thereto (the “Senior Credit Agreement”) that matures on May 31, 2015.  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, 2013.  As of June 30, 2013, we had $59.1 million outstanding, with remaining availability of $40.9 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 lender parties 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, which was 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, 2013, we had a principal amount of $175.0 million outstanding, with a discount of $4.1 million using the estimated market value interest rate at the time of issuance, for a net reported balance of $170.9 million.  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 under 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, 2012 for a more detailed description of our Credit Agreements and the covenants under the Credit Agreements.  At June 30, 2013, we were in compliance with the covenants.

It is expected that Contango’s secured revolving credit facility and our Senior Credit Agreement will be amended, restated or replaced effective as of the effective time of the Merger (as amended, restated or replaced, the “Combined Company Senior Credit Facility”) to reflect the consummation of the Merger. It is anticipated the borrowing base under the Combined Company Senior Credit Facility will likely be in

 
14

 


the range of $250—$275 million which is significantly larger than that under our Senior Credit Agreement and reflects the combined company’s proved crude oil and natural gas reserves. It is also expected that the obligations under the Combined Company Senior Credit Facility will be secured by a pledge of the assets of the combined company, including the capital stock of the subsidiaries of the combined company. Although we and Contango have not finalized the terms of any amendment, restatement or replacement of our respective credit facilities (including with respect to interest rates, restrictive covenants, events of default, guarantees and prepayment provisions) to date, extensive discussions have been held with a number of prospective lenders regarding the Combined Company Senior Credit Facility and lenders appear to view the Merger positively and wish to participate in a Combined Company Senior Credit Facility of the size noted above. However, no assurance may be given that a Combined Company Senior Credit Facility may be negotiated and completed.

It is also anticipated that, at or immediately following the effective time of the Merger, our Second Lien Credit Agreement will be terminated and any indebtedness thereunder repaid. The prepayment of indebtedness under the Second Lien Credit Agreement will require the payment of a prepayment fee equal to 1% of the principal amount repaid at or immediately following the effective time of the Merger. The combined company currently plans to fund the repayment of the indebtedness under the Second Lien Credit Agreement from Contango’s existing cash on hand and borrowings under the Combined Company Senior Credit Facility.

10.        LEGAL PROCEEDINGS

        From time to time, we are involved in legal proceedings relating to claims associated with our properties, operations or business or arising from disputes with vendors in the normal course of business, including the matters discussed below.

        Several class action lawsuits have been brought by Crimson stockholders in Delaware Chancery Court challenging the proposed Merger and seeking, among other things, injunctive relief to enjoin the defendants from completing the Merger on the agreed-upon terms, compensatory damages, and costs and disbursements relating to the lawsuits. Various combinations of Crimson, Contango, Merger Sub, members of Crimson’s board of directors, members of Crimson management and Oaktree Capital Management L.P. have been named as defendants in these lawsuits.

        These lawsuits have been consolidated into a single action for all purposes referred to as In Re: Crimson Exploration Inc. Stockholder Litigation; C.A. 8541-VCP (the “Consolidated Action”).

        The known plaintiffs in the Consolidated Action appear, based on the most current information of Crimson, to collectively own a very small percentage of the total outstanding shares of Crimson common stock. The lawsuits allege, among other things, that Crimson’s board of directors failed to take steps to obtain a fair price, failed to properly value Crimson, failed to protect against alleged conflicts of interest, failed to conduct a reasonably informed evaluation of whether the transaction was in the best interests of stockholders, failed to fully disclose all material information to stockholders, acted in bad faith and for improper motives, engaged in self-dealing, discouraged other strategic alternatives, took steps to avoid competitive bidding, and agreed to allegedly unreasonable deal protection mechanisms, including the no-shop and fiduciary-out provisions and termination fee. The lawsuits seek damages and injunctive relief. Additionally, on July 13, 2013, a separate and similar complaint was filed in the District Court of Harris County Texas, in the matter of Fisichella Family Trust v. Crimson Exploration Inc. It is possible that additional, similar lawsuits may be filed.

        One of the conditions to the closing of the Merger is that no order or injunction shall be in effect that prohibits consummation of the Merger.  Consequently, if a settlement or other resolution is not

 
15

 


reached in the lawsuits referenced above and the plaintiffs secure injunctive or other relief prohibiting, delaying or otherwise adversely affecting the defendants’ ability to complete the Merger, then such injunctive or other relief may prevent the Merger from becoming effective within the expected timeframe or at all.

See Item 3 of our Annual Report on Form 10-K for the year ended December 31, 2012 for a description of other legal proceedings to which we are subject.

11.         STOCKHOLDERS’ EQUITY

In the six months ended June 30, 2013, 542,121 shares of restricted Common Stock vested, of which 84,224 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 37,275 unvested shares of restricted Common Stock forfeited due to employee departures.  We also issued 16,458 shares pursuant to stock option exercises.  Discretionary grants of 642,000 shares of unvested restricted Common Stock were made to our employees during the six months ended June 30, 2013 as incentive-based equity compensation under the 2005 Stock Incentive Plan.  We also granted 71,205 shares of restricted Common Stock to three members of our board of directors as compensation pursuant to the Director Compensation Plan.

In the six months ended June 30, 2012, 303,016 shares of restricted Common Stock vested, of which 41,934 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 27,965 unvested shares of restricted Common Stock forfeited due to employee departures.  We also issued 2,897 shares pursuant to stock option exercises.  Discretionary grants of 954,000 shares of unvested restricted Common Stock were made to our employees during the six months ended June 30, 2012 as incentive-based equity compensation under the 2005 Stock Incentive Plan.  We also granted 54,879 shares of restricted Common Stock to three members of our board of directors as compensation pursuant to the Director Compensation Plan.

12.         INCOME TAXES

Income tax benefit for the six months ended June 30, 2013 was approximately $2.2 million compared to $12 thousand for the six months ended June 30, 2012.  The six months 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 previously recorded tax-adjusted $13.3 million valuation allowance.  The amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.

13.         RECENT ACCOUNTING PRONOUNCEMENTS

Accounting Standards Not Yet Adopted

In February 2013, the FASB issued ASU No. 2013-04— “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date”.  The objective of this update is to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP.  Examples of obligations within

 
16

 


the scope of this update include debt arrangements, other contractual obligations, and settled litigation and judicial rulings.  U.S. GAAP does not include specific guidance on accounting for such obligations with joint and several liability, which has resulted in diversity in practice.  The accounting update is effective for interim and annual periods beginning after December 15, 2013.  We are currently evaluating the provisions of this accounting update and assessing the impact, if any, it may have on our financial position and results of operations.

Further, we are closely monitoring the joint standard-setting efforts of the Financial Accounting Standards Board and the International Accounting Standards Board.  There are a large number of pending accounting standards that are being targeted for completion in 2013 and beyond, including, but not limited to, standards relating to revenue recognition, accounting for leases, fair value measurements, accounting for financial instruments, disclosure of loss contingencies and financial statement presentation.  Because these pending standards have not yet been finalized, at this time we are not able to determine the potential future impact that these standards will have, if any, on our financial position, results of operations or cash flows.


 
17

 

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

Cautionary Note Regarding 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 (this “Report”) 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, 2012. Statements in this discussion may be forward-looking.  These forward-looking statements involve risks and uncertainties, some of which are beyond our control.

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;
·  
future methods and types of financing and
·  
the proposed Merger, including the ability to complete the Merger in the anticipated timeframe or at all, the diversion of management in connection with the Merger and the combined company’s ability to realize fully or at all the anticipated benefits of the Merger.

We caution that a number of risks and uncertainties could cause our actual results to differ materially from the results implied by these or any other forward-looking statements made by us on our behalf.  Risks and uncertainties that could cause or contribute to such differences include, without limitation, those factors discussed in “ITEM 1A. Risk Factors” contained in our Annual Report filed on Form 10-K for the year ended December 31, 2012, as filed with the Securities and Exchange Commission.

We caution you that the forward-looking statements contained in this Report are not guarantees of future performance, and we cannot assure you that those statements will be realized or the forward-looking events and circumstances will occur.  All forward-looking statements speak only as of the respective dates thereof.

We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law.  These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.


 
18

 


We are an independent energy company engaged in the exploitation, exploration, development and acquisition of crude oil and natural gas properties.  Our operating areas include the onshore U.S. Gulf Coast, Texas and Colorado regions, which are generally characterized by high rates of return in known, prolific producing trends.  We have shifted our strategic focus to also include longer reserve life resource plays in Southeast Texas (the Woodbine oil and liquids-rich play) and South Texas (the Eagle Ford Shale and Buda oil and liquids-rich plays).  We believe these plays provide significant long-term growth potential from multiple formations.  Additionally, we have producing properties in the Denver Julesburg Basin (“DJ Basin”) in Weld and Adams counties in Colorado, which we believe may be prospective in the Niobrara Shale oil and liquids-rich play.  Until we see improvement in natural gas prices, we will focus our drilling activity predominantly on further developing our oil and liquids-rich assets.

As more fully described in Note 3 of the Notes to Consolidated Financial Statements, on April 29, 2013, Crimson entered into the Merger Agreement with Contango.  Subject to the terms and conditions of the Merger Agreement, at the Effective Time of the Merger, each share of Crimson common stock issued and outstanding will be converted into the right to receive 0.08288 shares of Contango Common Stock.

Unless expressly noted to the contrary, all forward-looking statements in the discussion and analysis of financial condition and results of operations that follows relate to Crimson on a stand-alone basis and are not reflective of the impact of the proposed merger with Contango.

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, 2013 Compared to Three Months Ended June 30, 2012

Revenues
   
Three months
ended June 30,
             
   
2013
   
2012
   
Change
   
Percent Change
 
Product revenues:
 
(in millions, except percentages)
 
Crude oil sales
  $ 26.4     $ 21.5     $ 4.9       22.8%  
Natural gas sales
    7.3       6.0       1.3       21.7%  
Natural gas liquids sales
    3.1       3.0       0.1       3.3%  
Product revenues
  $ 36.8     $ 30.5     $ 6.3          

Crude Oil, Natural Gas 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 commodity price hedging instruments, were $36.8 million for the second quarter of 2013 compared to $30.5 million for the second quarter of 2012, an increase resulting primarily from a 9.4% increase in equivalent production volumes and a 10.1% increase in realized equivalent prices.  The increase in equivalent production volumes was primarily due to a 29.3% increase in crude oil and natural gas liquids production.  The increase in equivalent realized prices resulted from the increase in liquids as a percentage of total production and a 30.8% increase in natural gas price realizations.

 
19

 


Production
   
Three months
ended June 30,
             
   
2013
   
2012
   
Change
   
Percent Change
 
Sales volumes:
                       
Crude oil (Bbl)
    253,457       197,185       56,272       28.5%  
Natural gas (Mcf)
    1,855,336       2,001,086       (145,750 )     -7.3%  
Natural gas liquids (Bbl)
    108,182       82,520       25,662       31.1%  
Natural gas equivalents (Mcfe) (1)
    4,025,170       3,679,316       345,854       9.4%  
% Crude oil and natural gas liquids
    53.9%       45.6%               8.3%  

(1)  
Equivalent volumes are based upon one barrel of crude oil or natural gas liquids equivalent to 6 Mcf of natural gas based on an approximation of equivalent energy content but are not equivalent in value

Quarterly production was approximately 4.0 Bcfe for the second quarter of 2013 compared to approximately 3.7 Bcfe for the second quarter of 2012.  On a daily basis, we produced an average of 44,233 Mcfe for the second quarter of 2013 compared to an average of 40,432 Mcfe for the second quarter of 2012.

Average Sales Prices
   
Three months
ended June 30,
             
   
2013
   
2012
   
Change
   
Percent Change
 
Average sales prices (before hedging):
                       
Crude oil (Bbl)
  $ 101.84     $ 106.09     $ (4.25 )     -4.0%  
Natural gas (Mcf)
    3.99       2.03       1.96       96.6%  
Natural gas liquids (Bbl)
    28.25       35.95       (7.70 )     -21.4%  
Natural gas equivalents (Mcfe)
    9.01       7.60       1.41       18.6%  

   
Three months
ended June 30,
             
   
2013
   
2012
   
Change
   
Percent Change
 
Average sales prices (after hedging):
                       
Crude oil (Bbl)
  $ 104.22     $ 109.06     $ (4.84 )     -4.4%  
Natural gas (Mcf)
    3.95       3.02       0.93       30.8%  
Natural gas liquids (Bbl)
    28.25       35.95       (7.70 )     -21.4%  
Natural gas equivalents (Mcfe)
    9.14       8.30       0.84       10.1%  

Crude oil, natural gas and natural gas liquids prices are reported net of the realized effects of our hedging agreements.  We realized gains of $0.6 million on our crude oil hedges and realized losses of $0.1 million on our natural gas hedges in the second quarter of 2013, compared to realized gains of $0.6 million for crude oil hedges and $2.0 million for natural gas hedges in the second quarter of 2012.


 
20

 


Costs and Expenses
   
Three months ended June 30,
             
   
2013
   
2012
   
Change
   
Percent Change
 
Selected operating expenses:
 
(in millions, except percentages)
 
Lease operating expenses
  $ 3.3     $ 3.6     $ (0.3 )     -8.3%  
Production and ad valorem taxes
    2.4       (2.5 )     4.9    
NC
 
Exploration expenses
    0.2             0.2          
General and administrative (1)
    6.1       3.9       2.2       56.4%  
Cash operating expenses
    12.0       5.0       7.0       140.0%  
Depreciation, depletion & amortization
    18.6       14.7       3.9       26.5%  
    Share-based compensation (1)
    0.7       0.6       0.1       16.7%  
Selected operating expenses (2)
  $ 31.3     $ 20.3     $ 11.0       54.2%  

(1)  
Total general and administrative costs on the Consolidated Statements of Operations include share-based compensation.
(2)  
Exclusive of impairments, abandonments and sales of assets.
     NC – not calculated

   
Three months ended June 30,
             
   
2013
   
2012
   
Change
   
Percent Change
 
Selected operating expenses ($ per Mcfe):
       
(in millions, except percentages)
       
Lease operating expenses
  $ 0.82     $ 0.98     $ (0.16 )     -16.3%  
Production and ad valorem taxes
    0.59       (0.68 )     1.27    
NC
 
Exploration expenses
    0.05       0.01       0.04       400.0%  
General and administrative (1)
    1.53       1.06       0.47       44.3%  
Cash operating expenses
    2.99       1.37       1.62       118.2%  
Depreciation, depletion & amortization
    4.62       3.99       0.63       15.8%  
Share-based compensation (1)
    0.17       0.17             0.0%  
Selected operating expenses ($ per Mcfe) (2)
  $ 7.78     $ 5.53     $ 2.25       40.7%  

(1)  
Total general and administrative costs on the Consolidated Statements of Operations include share-based compensation.
(2)  
Exclusive of impairments, abandonments and sales of assets.
     NC – not calculated

Lease Operating Expenses.  Lease operating expenses for the second quarter of 2013 were $3.3 million ($0.82 per Mcfe) compared to $3.6 million ($0.98 per Mcfe) in the second quarter of 2012, a decrease resulting primarily from lower workover expenses and improved field efficiencies.

Production and Ad Valorem Taxes.  Production and ad valorem taxes for the second quarter of 2013 were $2.4 million compared to a credit of $2.5 million for the second quarter of 2012, as the 2012 quarter included a $4.0 million credit for certain 2007-2012 severance taxes filed for and received from the State of Texas in 2012 for allowed marketing costs.  Exclusive of the severance tax credit refund made in June 2012, production and ad valorem taxes per Mcfe were $0.59 versus $0.42 for the second quarters 2013 and 2012, respectively.

Exploration Expenses. Exploration expenses were $0.2 million in the second quarter of 2013 compared to $49 thousand for the second quarter of 2012, a slight increase primarily due to higher settled asset retirement obligations incurred in the second quarter of 2013 compared to the second quarter of 2012.

 
21

 


Depreciation, Depletion and Amortization (“DD&A”).  DD&A expense for the second quarter of 2013 was $18.6 million compared to $14.7 million for the second quarter of 2012, an increase attributable to higher 2013 production and a higher DD&A rate associated with new drilling on our oil and liquids-rich plays.

Impairment of Oil and Gas Properties.  Non-cash impairment of oil and gas properties remained flat at $0.8 million for the second quarter of 2013 compared to the second quarter of 2012.  The impairments were the result of amortization of leasehold cost on individually insignificant unproved properties.

General and Administrative (“G&A”) Expenses.  Total G&A expenses were $6.8 million ($1.70 per Mcfe) for the second quarter of 2013 compared to $4.5 million ($1.23 per Mcfe) for the second quarter of 2012.  Included in G&A expense is a non-cash stock expense of $0.7 million ($0.17 per Mcfe) versus $0.6 million ($0.17 per Mcfe) in the second quarters of 2013 and 2012, respectively.  G&A expenses increased primarily due to higher personnel costs and merger-related professional fees.

Interest Expense.  Interest expense was $6.3 million for the second quarter of 2013 compared to $6.2 million for the second quarter of 2012.

Other Income (Expense) and Financing Costs.  Other income (expense) and financing costs were $0.1 million for the second quarter 2013 compared to $0.1 million for the second quarter of 2012.  These amounts 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.

Unrealized Gain on Derivative Instruments.  The non-cash unrealized gain on derivative instruments for the second quarter of 2013 was $2.6 million compared to $3.0 million for the second quarter of 2012.  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 hedged.

Income Tax.  Net income before taxes was $0.9 million for the second quarter of 2013 compared to $6.1 million in the second quarter of 2012.  After adjusting for permanent tax differences, we recorded an income tax expense of $0.3 million for the second quarter of 2013, compared to $2.2 million for the second quarter of 2012.  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 previously recorded tax-adjusted $13.3 million valuation allowance.  The amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.


 
22

 


Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012
 
Revenues
   
Six months
ended June 30,
             
   
2013
 
2012
   
Change
   
Percent Change
 
Product revenues:
 
(in millions, except percentages)
 
Crude oil sales
  $ 42.5     $ 38.4     $ 4.1       10.7%  
Natural gas sales
    13.3       13.1       0.2       1.5%  
Natural gas liquids sales
    5.1       5.7       (0.6 )     -10.5%  
Product revenues
  $ 60.9     $ 57.2     $ 3.7       6.5%  

Crude Oil, Natural Gas 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 $60.9 million for the first six months of 2013 compared to $57.2 million for the first six months of 2012.  Equivalent production volumes increased by 1.2%, while higher-value crude oil and natural gas liquids volumes increased from approximately 42% to 49% of total equivalent volumes.  Realized prices increased as a result of the improved product mix and a 15% increase in realized natural gas prices.

Production
   
Six months
ended June 30,
             
   
2013
   
2012
   
Change
   
Percent Change
 
Sales volumes:
                       
Crude oil (Bbl)
    406,499       355,818       50,681       14.2%  
Natural gas (Mcf)
    3,679,888       4,165,211       (485,323 )     -11.7%  
Natural gas liquids (Bbl)
    189,906       145,056       44,850       30.9%  
Natural gas equivalents (Mcfe) (1)
    7,258,318       7,170,455       87,863       1.2%  
% Crude oil and natural gas liquids
    49.3%       41.9%               7.4%  

(1)  
Equivalent volumes are based upon one barrel of crude oil or natural gas liquids equivalent to 6 Mcf of natural gas based on an approximation of equivalent energy content but are not equivalent in value

Production was approximately 7.3 Bcfe for the first six months of 2013 compared to 7.2 Bcfe for the first six months of 2012.  On a daily basis, we produced an average of 40,101 Mcfe in the first six months of 2013 compared to an average of 39,398 Mcfe in the first six months of 2012, with oil and liquids production increasing to approximately 49% of total equivalent production in 2013 due to our continued focus on drilling our oil and liquids-rich plays.

Average Sales Prices
   
Six months
ended June 30,
             
   
2013
   
2012
   
Change
   
Percent Change
 
Average sales prices (before hedging):
                       
Crude oil (Bbl)
  $ 103.60     $ 106.72     $ (3.12 )     -2.9%  
Natural gas (Mcf)
    3.61       2.30       1.31       57.0%  
Natural gas liquids (Bbl)
    26.62       39.24       (12.62 )     -32.2%  
Natural gas equivalents (Mcfe)
    8.33       7.43       0.90       12.1%  
 
 
 
23

 
 
   
Six months
ended June 30,
             
   
2013
   
2012
   
Change
   
Percent Change
 
Average sales prices (after hedging):
                       
Crude oil (Bbl)
  $ 104.57     $ 107.92     $ (3.35 )     3.1%  
Natural gas (Mcf)
    3.62       3.15       0.47       14.9%  
Natural gas liquids (Bbl)
    26.62       39.24       (12.62 )     -32.2%  
Natural gas equivalents (Mcfe)
    8.39       7.98       0.41       5.1%  

Crude oil, natural gas and natural gas liquids prices are reported net of the realized effect of our hedging agreements.  We realized gains of $0.4 million on our crude oil hedges and $0.1 million on our natural gas hedges in the first six months of 2013, compared to realized gains of $0.4 million on our crude oil hedges and $3.5 million on our natural gas hedges in the first six months of 2012.

Costs and Expenses
   
Six months ended June 30,
             
   
2013
   
2012
   
Change
   
Percent Change
 
Selected operating expenses:
 
(in millions, except percentages)
 
Lease operating expenses
  $ 6.6     $ 8.2     $ (1.6 )     -19.5%  
Production and ad valorem taxes
    4.1       (1.1 )     5.2    
NC
 
Exploration expenses
    0.3       0.3             0.0%  
General and administrative (1)
    9.8       8.1       1.7       21.0%  
Cash operating expenses
    20.8       15.5       5.3       34.2%  
Depreciation, depletion & amortization
    31.5       29.1       2.4       8.2%  
Share-based compensation (1)
    1.4       1.2       0.2       16.7%  
Selected operating expenses (2)
  $ 53.7     $ 45.8     $ 7.9       17.2%  

(1)  
Total general and administrative costs on the Consolidated Statements of Operations include share-based compensation.
(2)  
Exclusive of impairments, abandonments and sales of assets.
     NC – not calculated


   
Six months ended June 30,
             
   
2013
   
2012
   
Change
   
Percent Change
 
Selected operating expenses ($ per Mcfe):
       
(in millions, except percentages)
       
Lease operating expenses
  $ 0.90     $ 1.15     $ (0.25 )     -21.7%  
Production and ad valorem taxes
    0.56       (0.15 )     0.71    
NC
 
Exploration expenses
    0.04       0.05       (0.01 )     -20.0%  
General and administrative (1)
    1.35       1.13       0.22       19.5%  
Operating expenses
    2.85       2.18       0.67       30.7%  
Depreciation, depletion & amortization
    4.33       4.06       0.27       6.7%  
Share-based compensation (1)
    0.19       0.16       0.03       18.8%  
Selected operating expenses (2)
  $ 7.37     $ 6.40     $ 0.97       15.2%  

(1)  
Total general and administrative costs on the Consolidated Statements of Operations include share-based compensation.
(2)  
Exclusive of impairments, abandonments and sales of assets.
     NC – not calculated

 
24

 


Lease Operating Expenses.  Lease operating expenses for the first six months of 2013 were $6.6 million ($0.90 per Mcfe) compared to $8.2 million ($1.15 per Mcfe) in the first six months of 2012, a decrease resulting from lower workover expenses and improved field efficiencies.

Production and Ad Valorem Taxes.  Production and ad valorem taxes for the first six months of 2013 were $4.1 million compared to a credit of $1.1 million for the first six months of 2012, as the 2012 quarter included a $4.0 million credit for certain 2007-2012 severance taxes filed for and received from the State of Texas in 2012 for allowed marketing costs.  Exclusive of the severance tax credit refund made in June 2012, production and ad valorem taxes per Mcfe were $0.56 versus $0.41 for the second quarters 2013 and 2012, respectively.

Exploration Expenses.  Exploration expenses remained flat at $0.3 million in the first six months of 2013 and for the first six months of 2012.

Depreciation, Depletion and Amortization (“DD&A”).  DD&A expense for the first six months of 2013 was $31.5 million compared to $29.1 million for the first six months of 2012, an increase attributable to higher 2013 production and a higher DD&A rate associated with our oil and liquids-rich plays.

Impairment of Oil and Gas Properties.  Non-cash impairment of oil and gas properties for the first six months of 2013 was $1.6 million compared to $1.5 million for the first six months of 2012.  The impairments were the result of amortization of leasehold costs on individually insignificant unproved properties.

General and Administrative (“G&A”) Expenses.  Total G&A expenses were $11.2 million ($1.54 per Mcfe) for the first six months of 2013 compared to $9.3 million ($1.30 per Mcfe) for the first six months of 2012, which includes non-cash stock expense of $1.4 million ($0.19 per Mcfe) and $1.2 million ($0.16 per Mcfe) for the first six months of 2013 and 2012, respectively.  G&A expenses increased primarily due to higher personnel costs and merger-related professional fees.

Interest Expense.  Interest expense was $12.6 million for the first six months of 2013 compared to $12.5 million for the first six months of 2012.  Total interest expense increased slightly primarily due to slightly higher debt principal.

Other Income (Expense) and Financing Costs.  Other income (expense) and financing costs were $0.3 million for the first six months of 2013 compared with $0.3 million for the first six months of 2012.  These amounts 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.

Unrealized Gain (Loss) on Derivative Instruments.  The non-cash unrealized gain for the first six months of 2013 was $0.8 million compared with a gain of $2.5 million for the first six months of 2012.  Unrealized gain or loss is the change in the mark-to-market exposure under 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 hedged.

Income Tax.  Our net loss before taxes was $6.4 million for the first six months of 2013 compared to $0.5 million for the first six months of 2012.  After adjusting for permanent tax differences, we recorded an income tax benefit of approximately $2.2 million for the first six months of 2013, compared to $12 thousand for the first six months of 2012.  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

 
25

 


believe it is more likely than not that we will realize the benefits of these deductible differences net of a previously recorded tax-adjusted $13.3 million valuation allowance.  The amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.

Liquidity and Capital Resources

Our primary cash requirements are for capital expenditures (including acquisitions), working capital, operating expenses 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 reduce our capital expenditures.

Liquidity and Cash Flow

Our working capital deficit was $26.5 million as of June 30, 2013 compared to $13.9 million as of December 31, 2012.  The following table provides the components and changes in working capital as of June 30, 2013 and December 31, 2012.

   
June 30, 2013
   
December 31, 2012
   
Change
 
Current assets
 
(in millions)
 
Accounts receivable, net
  $ 13.9     $ 11.7     $ 2.2  
Prepaid expenses
    0.8       0.8        
Derivative instruments
    2.1       1.9       0.2  
Deferred tax asset, net
    10.9       10.4       0.5  
Total current assets
    27.7       24.8       2.9  
                         
Current liabilities
                       
Accounts payable and accrued liabilities (1)
    52.8       37.8       15.0  
Asset retirement obligations
    1.4       0.9       0.5  
Deferred tax liability, net
                 
Total current liabilities
    54.2       38.7       15.5  
                         
Working capital (deficit)
  $ (26.5 )   $ (13.9 )   $ (12.6 )

(1)  
Reflects impact of timing of capital expenditures payable.


 
26

 


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, 2013 and 2012, respectively.

   
Six months ended
June 30,
 
   
2013
   
2012
 
Financial Measures
 
(in millions)
 
Net cash provided by operating activities
  $ 40.8     $ 23.3  
Net cash used in investing activities
    (30.5 )     (59.9 )
Net cash (used in) provided by financing activities
    (10.3 )     36.6  
Cash and cash equivalents
           

During the first six months of 2013, the net cash provided by operating activities, before changes in working capital, was $27.9 million, compared to $29.5 million for the first six months of 2012, primarily due to the $4.0 million severance tax credit received in 2012.

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

Net cash (used in) provided by financing activities, which consists primarily of net borrowings (repayments) on our revolving credit agreement, changed primarily due to temporary funding of our accelerated 2012 drilling activity.

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 lender parties thereto (the “Senior Credit Agreement”) that matures on May 31, 2015.  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, 2013.  The credit agreement also provides for the issuance of letters-of-credit up to a $5.0 million sub-limit.  As of June 30, 2013, we had $59.1 million outstanding, with remaining availability of $40.9 million under our Senior Credit Agreement.

Advances under our Senior 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 1.75% and 2.75%, for LIBOR loans, and between 0.75% and 1.75%, 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 between 0.375% and 0.500% depending on the borrowing base utilization.

We also maintain a second lien credit agreement dated December 27, 2010 with Barclays Bank Plc, as agent, and the lender parties thereto, including an affiliate of OCM GW Holdings, LLC (“Oaktree Holdings”), our largest stockholder (the “Second Lien Credit Agreement”).  The Second Lien Credit

 
27

 


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, 2013, we had a principal amount of $175.0 million outstanding, with a discount of $4.1 million using the estimated market value interest rate at the time of issuance, for a net reported balance of $170.9 million.

Advances under our 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 Senior 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 Senior Credit Agreement.  Unpaid interest is payable under our credit agreements as interim borrowings mature.

We utilize commodity price hedge instruments to minimize exposure to declining prices on our crude oil, natural gas and natural gas liquids production.  We use a series of swaps and costless collars to accomplish our commodity hedging position.  We currently have 4.7 Bcfe of equivalent production hedged for the remainder of 2013, consisting of 2.0 Bcf of natural gas hedges at NYMEX prices and 324 MBbl of crude oil hedges at WTI prices and 117 MBbl of crude oil hedges at Brent prices.  We also have 2.1 Bcfe of equivalent production hedged for 2014, consisting of 1.0 Bcf of natural gas hedges at NYMEX prices and 174 MBbl of crude oil hedges at Brent prices.

Future Capital Requirements

        Our future crude oil, natural gas 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 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 South, Southeast and East Texas and Colorado and in our conventional inventory, with activity in any particular area to be a function of market and field economics.  In the short term, due to the low natural gas price environment, and the superior economics from oil production, we will focus the majority of our capital expenditures on the development of our South Texas and Southeast Texas crude oil and natural gas liquids rich project inventory.  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 Senior Credit Agreement, will be sufficient to meet the liquidity requirements necessary to fund our daily operations planned capital development and debt service requirements for the next twelve months.  We currently plan to limit our 2013 capital expenditures to our forecasted cash flow from operations for the year; however, we do possess the capacity, through our Senior Credit Agreement, to increase and/or accelerate drilling on any particular area should we determine that market and project economics so warrant.  The vast majority of our planned capital expenditures for 2013 are on acreage that is currently held by existing production; therefore, we also possess the flexibility of reducing or deferring our capital expenditures, if deemed appropriate without the risk of significant lease expirations.  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

 
28

 


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 Senior Credit Agreement in connection with a borrowing base redetermination.  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.  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, 2012.

Recent Accounting Pronouncements

In February 2013, the FASB issued ASU No. 2013-04— “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date”.  The objective of this update is to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP.  Examples of obligations within the scope of this update include debt arrangements, other contractual obligations, and settled litigation and judicial rulings.  U.S. GAAP does not include specific guidance on accounting for such obligations with joint and several liability, which has resulted in diversity in practice.  The accounting update is effective for interim and annual periods beginning after December 15, 2013.  We are currently evaluating the provisions of this accounting update and assessing the impact, if any, it may have on our financial position and results of operations.

        Further, we are closely monitoring the joint standard-setting efforts of the Financial Accounting Standards Board and the International Accounting Standards Board.  There are a large number of pending accounting standards that are being targeted for completion in 2013 and beyond, including, but not limited to, standards relating to revenue recognition, accounting for leases, fair value measurements, accounting for financial instruments, disclosure of loss contingencies and financial statement presentation.  Because these pending standards have not yet been finalized, at this time we are not able to determine the potential future impact that these standards will have, if any, on our financial position, results of operations or cash flows.

ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are currently exposed to market risk primarily related to adverse changes in crude oil, natural gas and natural gas liquids prices. We use derivative instruments to manage our commodity price risk caused by fluctuating prices. We do not enter into derivative instruments for trading purposes. For information regarding our exposure to certain market risks, see Item 7A. “Quantitative and Qualitative Disclosure About Market Risk” in our Annual Report on Form 10-K for the year ended December 31, 2012 and Note 5 – Derivative Instruments included in Part I. Item 1. Financial Statements of this Report.

Commodity Price Risk

In the past we have entered into, and may in the future enter into, certain derivative arrangements with respect to portions of our crude oil, natural gas and natural gas liquids production, to reduce our

 
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sensitivity to volatile commodity prices.  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 crude oil, natural gas and natural gas liquids.  Moreover, our derivative arrangements apply only to a portion of our production and provide only partial protection against declines in commodity prices.  Such arrangements may expose us to risk of financial loss in certain circumstances.  We expect that the monthly volume of derivative arrangements will vary from time to time.  We continuously reevaluate our hedging program in light of increases in production, market conditions, commodity price forecasts, capital spending and debt service requirements.

At June 30, 2013, we had entered into swaps and costless collars related to future crude oil and natural gas sales with a net fair value of $2.7 million.  A price increase of $1.00 per Bbl of crude oil would decrease the net fair value of our commodity derivatives by approximately $0.2 million.  A price increase of $0.10 per MMBtu for natural gas would decrease the net fair value of our commodity derivatives by approximately $0.2 million.

Interest Rate Risk

We are exposed to interest rate risk on debt with variable interest rates.  In the past we have entered into, and may in the future enter into, interest rate swap agreements.  Changes in interest rates affect the amount of interest we pay on borrowings under our Senior Credit Agreement and our Second Lien Credit Agreement.  At June 30, 2013, we did not have any outstanding interest rate swap agreements.  Assuming our current level of borrowings, a 100 basis point increase in the interest rates we pay under our Senior Credit Agreement would result in an increase of our interest expense by $0.6 million for a twelve month period, assuming current debt levels.

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 three months ended June 30, 2013, 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 1.
LEGAL PROCEEDINGS

        From time to time, we are involved in legal proceedings relating to claims associated with our properties, operations or business or arising from disputes with vendors in the normal course of business.  See Legal Proceedings in Note 10 of the notes to the consolidated financial statements in Part I, Item 1 of this report, which information is incorporated herein by reference, for a description of matters arising since the disclosure of legal proceedings to which we are subject as described in Item 3 of our Annual Report on Form 10–K for the year ended December 31, 2012.

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, 2012, 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.  Prior to the date of this report, additional risk factors related to the Merger with Contango arose in addition to those previously disclosed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012.  The additional risk factors are presented below.

Uncertainties associated with the Merger may cause a loss of management personnel and other key employees, which could adversely affect the future business and operations of the combined company.

        We are dependent on the experience and industry knowledge of our officers and other key employees to execute our business plans. Our success until the Merger and the combined company’s success after the Merger will depend in part upon our ability to retain key management personnel and other key employees. Current and prospective employees of Crimson may experience uncertainty about their roles within the combined company following the Merger, which may have an adverse effect on our ability to attract or retain key management and other key personnel. Accordingly, no assurance can be given that the combined company will be able to attract or retain key management personnel and other key employees of Crimson to the same extent that Crimson had previously been able to attract or retain its own employees.
 
        The transactions are subject to conditions, including certain conditions that may not be satisfied, or completed on a timely basis, if at all.
 
        The Merger is subject to a number of other conditions beyond our control that may prevent, delay or otherwise materially adversely affect its completion. We cannot predict whether and when these other conditions will be satisfied. Any delay in completing the Merger could cause the combined company not to realize some or all of the synergies that we expect to achieve if the Merger is successfully completed within its expected time frame.

        Failure to complete the Merger could negatively impact our future business and financial results.

        We can make no assurances that we will be able to satisfy all of the conditions to the Merger or succeed in any litigation brought in connection with the Merger. If the Merger is not completed, our

 
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financial results may be adversely affected and we will be subject to several risks, including but not limited to:

·  
being required to pay a termination fee of $7 million or an expense reimbursement of $4.5 million, under certain circumstances provided in the Merger Agreement;
·  
payment of costs relating to the Merger, such as legal, accounting, financial advisor and printing fees, whether or not the Merger is completed;
·  
having had the focus of our management on the Merger instead of on pursuing other opportunities that could have been beneficial to us; and
·  
being subject to litigation related to any failure to complete the Merger.

        If the Merger is not completed, we cannot assure our stockholders that these risks will not materialize and will not materially and adversely affect our business, financial results and stock price.

        Several lawsuits have been filed against Crimson and other interested parties challenging the Merger, and an adverse ruling may prevent the Merger from being completed.

        Several class action lawsuits have been brought by Crimson stockholders in Delaware Chancery Court challenging the proposed Merger and seeking, among other things, injunctive relief to enjoin the defendants from completing the Merger on the agreed-upon terms, compensatory damages, and costs and disbursements relating to the lawsuits. Various combinations of Crimson, Contango, Merger Sub, members of Crimson’s board of directors, members of Crimson management and Oaktree Capital Management L.P. have been named as defendants in these lawsuits.

        These lawsuits have been consolidated into a single action for all purposes referred to as In Re: Crimson Exploration Inc. Stockholder Litigation; C.A. 8541-VCP (the “Consolidated Action”).

        The known plaintiffs in the Consolidated Action appear, based on the most current information of Crimson, to collectively own a very small percentage of the total outstanding shares of Crimson common stock. The lawsuits allege, among other things, that Crimson’s board of directors failed to take steps to obtain a fair price, failed to properly value Crimson, failed to protect against alleged conflicts of interest, failed to conduct a reasonably informed evaluation of whether the transaction was in the best interests of stockholders, failed to fully disclose all material information to stockholders, acted in bad faith and for improper motives, engaged in self-dealing, discouraged other strategic alternatives, took steps to avoid competitive bidding, and agreed to allegedly unreasonable deal protection mechanisms, including the no-shop and fiduciary-out provisions and termination fee. The lawsuits seek damages and injunctive relief. Additionally, on July 13, 2013, a separate and similar complaint was filed in the District Court of Harris County Texas, in the matter of Fisichella Family Trust v. Crimson Exploration Inc. It is possible that additional, similar lawsuits may be filed.

        One of the conditions to the closing of the Merger is that no order or injunction shall be in effect that prohibits consummation of the Merger.  Consequently, if a settlement or other resolution is not reached in the lawsuits referenced above and the plaintiffs secure injunctive or other relief prohibiting, delaying or otherwise adversely affecting the defendants’ ability to complete the Merger, then such injunctive or other relief may prevent the Merger from becoming effective within the expected timeframe or at all.

        See Item 3 of our Annual Report on Form 10-K for the year ended December 31, 2012 for a description of other legal proceedings to which we are subject.

 
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        The Merger Agreement contains provisions that limit our ability to pursue alternatives to the Merger, could discourage a potential competing acquiror of Crimson from making a favorable alternative transaction proposal and, in specified circumstances, could require us to pay a termination fee to the other party.

        The Merger Agreement contains “no shop” provisions that, subject to limited exceptions, restrict our ability to solicit, initiate, or knowingly encourage or knowingly facilitate, directly or indirectly, any inquiry or proposal in respect of a competing third-party proposal for the acquisition of our stock or assets. In addition, we are generally required to negotiate in good faith to modify the terms of the Merger in response to any competing acquisition proposals before our board of directors may withdraw or qualify its recommendation with respect to the Merger. In some circumstances, upon termination of the merger agreement, a termination fee or an expense reimbursement of $4.5 million will be required to be paid from one party to the other. If Crimson is required to pay a termination fee, such fee would be $7 million.

        These provisions could discourage a potential third-party acquiror that might have an interest in acquiring all or a significant portion of Crimson from considering or proposing that acquisition, even if it were prepared to pay consideration with a higher per share cash or market value than the market value proposed to be received or realized in the Merger or might result in a potential third-party acquiror proposing to pay a lower price to the stockholders than it might otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances.

        If the Merger Agreement is terminated and we determine to seek another business combination, we may not be able to negotiate a transaction with another party on terms comparable to, or better than, the terms of the Merger.

        Completion of the Merger transactions may trigger change in control or other provisions in certain agreements to which we are a party.

        The completion of the transactions may trigger change in control or other provisions in certain agreements to which we are a party. If we are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially terminating the agreements or seeking monetary damages. Even if we are able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements on terms less favorable to us or the combined company.


 
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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 2013.  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, 2013
    8,725     $ 3.05       8,725       (1)  
June 1-30, 2013
    2,905     $ 2.95       2,905       (1)  
Total
    11,630               11,630          

     (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.  Company policy and the 2005 Stock Incentive Plan provide for the withholding of shares to satisfy tax obligations.

ITEM 6.
EXHIBITS

Number
 
Description
 
     
 2.1
 
Agreement and Plan of Merger, dated as of April 29, 2013, among Contango, Merger Sub and Crimson (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on April 30, 2013)
     
 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
 
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)
     
 3.3
 
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)
     
 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)
 
 
 
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Number
 
Description
 
     
 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
 
Support Agreement, dated as of April 29, 2013, by and between Joseph J. Romano and Crimson (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 30, 2013)
     
 10.2
 
Support Agreement, dated as of April 29, 2013, by and between Sergio Castro and Crimson (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on April 30, 2013)
     
 10.3
 
Support Agreement, dated as of April 29, 2013, by and between Yaroslava Makalskaya and Crimson (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on April 30, 2013)
     
 10.4
 
Support Agreement, dated as of April 29, 2013, by and between Brad Juneau and Crimson (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on April 30, 2013)
     
 10.5
 
Support Agreement, dated as of April 29, 2013, by and between Joseph J. Romano, as Temporary Administrator of the Estate of Kenneth R. Peak, and Crimson (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on April 30, 2013)
 
       
 10.6
 
Support Agreement, dated as of April 29, 2013, by and among Allan D. Keel, Contango and Merger Sub (incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on April 30, 2013)
 
       
 10.7
 
Support Agreement, dated as of April 29, 2013, by and among E. Joseph Grady, Contango and Merger Sub (incorporated by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K filed on April 30, 2013)