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Escalera Resources Co. 10-Q 2010

Documents found in this filing:

  1. 10-Q
  2. Ex-31.1
  3. Ex-31.2
  4. Ex-32
  5. Ex-32
Form 10-Q
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2010
or
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File Number 1-33571
DOUBLE EAGLE PETROLEUM CO.
(Exact name of registrant as specified in its charter)
     
MARYLAND   83-0214692
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. employer
identification no.)
1675 Broadway, Suite 2200, Denver, Colorado 80202
(Address of principal executive offices) (Zip code)
303-794-8445
(Registrant’s telephone number, including area code)
None
(Former name, former address, and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ 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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
             
Large accelerated filer o   Accelerated filer o   Non-accelerated filer þ (Do not check if a small reporting company)   Small reporting Company o
Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
     
Class
Common stock, $.10 par value
  Outstanding as of July 30, 2010
11,128,936
 
 

 


 

DOUBLE EAGLE PETROLEUM CO.
FORM 10-Q
TABLE OF CONTENTS
         
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 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32

 

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Table of Contents

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands of dollars except share and per share data)
(Unaudited)
                 
    June 30,     December 31,  
    2010     2009  
 
               
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 4,192     $ 5,682  
Cash held in escrow
    613       611  
Accounts receivable
    6,013       6,772  
Assets from price risk management
    4,425        
Other current assets
    4,666       3,982  
 
           
Total current assets
    19,909       17,047  
 
           
 
               
Oil and gas properties and equipment, successful efforts method:
               
Developed properties
    170,789       165,279  
Wells in progress
    5,577       7,544  
Gas transportation pipeline
    5,465       5,465  
Undeveloped properties
    2,845       2,502  
Corporate and other assets
    1,895       1,914  
 
           
 
    186,571       182,704  
Less accumulated depreciation, depletion and amortization
    (62,723 )     (53,682 )
 
           
Net properties and equipment
    123,848       129,022  
 
           
Assets from price risk management
    3,268       3,566  
Other assets
    822       859  
 
           
TOTAL ASSETS
  $ 147,847     $ 150,494  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
 
               
Current liabilities:
               
Accounts payable
  $ 3,643     $ 6,177  
Accrued expenses
    4,661       6,918  
Liabilities from price risk management
          4,739  
Accrued production taxes
    3,648       2,439  
Capital lease obligations, current portion
    539       533  
Other current liabilities
    308       308  
 
           
Total current liabilities
    12,799       21,114  
 
               
Line of credit
    31,000       34,000  
Asset retirement obligation
    4,709       4,807  
Liabilities from price risk management
          430  
Deferred tax liability
    8,616       4,620  
Capital lease obligations, long-term portion
    274       545  
Other long-term liabilities
    128       282  
 
           
Total liabilities
    57,526       65,798  
 
           
 
               
Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 shares issued and outstanding as of June 30, 2010 and December 31, 2009
    37,972       37,972  
 
               
Stockholders’ equity:
               
Common stock, $0.10 par value; 50,000,000 shares authorized; 11,116,591 and 11,090,725 shares issued and outstanding as of June 30, 2010 and December 31, 2009, respectively
    1,112       1,109  
Additional paid-in capital
    44,136       43,640  
Retained earnings
    3,021       (342 )
Accumulated other comprehensive income
    4,080       2,317  
 
           
Total stockholders’ equity
    52,349       46,724  
 
           
 
               
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 147,847     $ 150,494  
 
           
The accompanying notes are an integral part of the consolidated financial statements.

 

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Table of Contents

DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED STATEMENTS OF INCOME
(Amounts in thousands of dollars except share and per share data)
(Unaudited)
                                 
    Three months ended June 30,     Six months ended June 30,  
    2010     2009     2010     2009  
 
                               
Revenues
                               
Oil and gas sales
  $ 7,608     $ 10,492       18,657     $ 20,992  
Transportation revenue
    1,401       1,583       2,889       3,170  
Price risk management activities
    103       (2,152 )     7,925       (3,292 )
Other income, net
    280       117       357       210  
 
                       
 
                               
Total revenues
    9,392       10,040       29,828       21,080  
 
                       
 
                               
Costs and expenses
                               
Production costs
    2,397       1,989       4,339       3,601  
Production taxes
    1,010       753       2,309       1,642  
Exploration expenses including dry hole costs
    28       29       66       55  
Pipeline operating costs
    971       1,087       2,119       1,654  
General and administrative
    1,392       1,427       2,925       3,101  
Impairment and abandonment of equipment and properties
    80             80        
Depreciation, depletion and amortization
    4,530       4,715       9,070       9,097  
 
                       
 
                               
Total costs and expenses
    10,408       10,000       20,908       19,150  
 
                       
 
                               
Income from operations
    (1,016 )     40       8,920       1,930  
 
                               
Interest expense, net
    (385 )     (392 )     (750 )     (644 )
 
                       
 
                               
Income (loss) before income taxes
    (1,401 )     (352 )     8,170       1,286  
 
                               
Benefit (provision) for deferred income taxes
    512       110       (2,945 )     (521 )
 
                       
 
                               
NET INCOME (LOSS)
  $ (889 )   $ (242 )   $ 5,225     $ 765  
 
                       
 
                               
Preferred stock dividends
    931       931       1,862       1,862  
 
                       
 
                               
Net income (loss) attributable to common stock
  $ (1,820 )   $ (1,173 )   $ 3,363     $ (1,097 )
 
                       
 
                               
Net income (loss) per common share:
                               
Basic
  $ (0.16 )   $ (0.13 )   $ 0.30     $ (0.12 )
 
                       
Diluted
  $ (0.16 )   $ (0.13 )   $ 0.30     $ (0.12 )
 
                       
 
                               
Weighted average shares outstanding:
                               
Basic
    11,116,476       9,233,725       11,111,092       9,217,902  
 
                       
Diluted
    11,116,476       9,233,725       11,111,092       9,217,902  
 
                       
The accompanying notes are an integral part of the consolidated financial statements.

 

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Table of Contents

DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands of dollars)
(Unaudited)
                 
    Six months ended June 30,  
    2010     2009  
 
               
Cash flows from operating activities:
               
Net income
  $ 5,225     $ 765  
Adjustments to reconcile net income to net cash from operating activities:
               
Depreciation, depletion, amortization and accretion of asset retirement obligation
    9,125       9,147  
Abandonment of non-producing properties and leases
    80       6  
Provision for deferred taxes
    2,945       521  
Employee stock option expense
    398       693  
Directors fees paid in stock
    98       77  
Non-cash gain on transfer of asset retirement obligation to third party
    (164 )      
Change in fair value of derivative contracts
    (6,482 )     6,218  
Revenue from carried interest
    (1,282 )     (954 )
Gain on sale of producing property
    (142 )     (140 )
Changes in current assets and liabilities:
               
Increase in deposit held in escrow
    (2 )     (3 )
Decrease in accounts receivable
    784       14,137  
Increase in other current assets
    (728 )     (99 )
Decrease in accounts payable
    (1,471 )     (13,369 )
Increase (Decrease) in accrued expenses
    1,667       (1,007 )
Increase in accrued production taxes
    667       834  
 
           
 
               
NET CASH PROVIDED BY OPERATING ACTIVITIES
    10,718       16,826  
 
           
 
               
Cash flows from investing activities:
               
Additions of producing properties and equipment, net
    (6,652 )     (28,315 )
Additions of corporate and non-producing properties
    (439 )     (15 )
Sale of corporate assets
    7        
Payment of acquisition related costs
          (320 )
 
           
 
               
NET CASH USED IN INVESTING ACTIVITIES
    (7,084 )     (28,650 )
 
           
 
               
Cash flows from financing activities:
               
Principal payments on capital lease obligations
    (265 )     (259 )
Issuance of stock under Company stock plans
    6       5  
Tax withholdings related to net share settlement of restricted stock awards
    (3 )     (23 )
Preferred stock dividends
    (1,862 )     (1,862 )
Net borrowings (repayments) on credit facility
    (3,000 )     17,861  
 
           
 
               
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
    (5,124 )     15,722  
 
           
 
               
Change in cash and cash equivalents
    (1,490 )     3,898  
 
               
Cash and cash equivalents at beginning of period
    5,682        
 
           
 
               
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 4,192     $ 3,898  
 
           
 
               
Supplemental disclosure of cash and non-cash transactions:
               
Cash paid for interest
  $ 824     $ 1,233  
Interest capitalized
  $ 87     $ 643  
Adjustment to joint interest partners’ well costs associated with unitization of Catalina
  $     $ 1,252  
Additions to developed properties included in current liabilities
  $ 4,128     $ 6,832  
Share-based compensation expense
  $ 496     $ 770  
The accompanying notes are an integral part of the consolidated financial statements.

 

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DOUBLE EAGLE PETROLEUM CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Amounts in thousands of dollars except share and per share data)
(Unaudited)
1. Summary of Significant Accounting Policies
Basis of presentation
The accompanying unaudited interim consolidated financial statements were prepared by Double Eagle Petroleum Co. (“Double Eagle” or the “Company”) pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Certain information and note disclosures normally included in the annual consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted as allowed by such rules and regulations. These consolidated financial statements include all of the adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and results of operations. All such adjustments are of a normal recurring nature only. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full fiscal year.
Certain amounts in the 2009 consolidated financial statements have been reclassified to conform to the 2010 consolidated financial statement presentation. Such reclassifications had no effect on net income.
The accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in the Annual Report on Form 10-K for the year ended December 31, 2009, and are supplemented throughout the notes to this Quarterly Report on Form 10-Q.
The interim consolidated financial statements presented herein should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2009 included in the Annual Report on Form 10-K filed with the SEC.
Principles of consolidation
The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Petrosearch Energy Corporation (“Petrosearch”) and Eastern Washakie Midstream LLC (“EWM”) (collectively, the “Company”). In August 2009, the Company acquired Petrosearch, which has operations in Texas and Oklahoma. The Company sold transportation assets located in the Catalina Unit, at cost, to EWM in exchange for an intercompany note receivable bearing interest of 5% per annum, maturing on January 31, 2028. The note and related interest are fully eliminated in consolidation. In addition, the Company has an agreement with EWM under which the Company pays a fee to EWM to gather and compress gas produced at the Catalina Unit. The Company’s share of the fee related to gas gathering is also eliminated in consolidation.
Recently adopted accounting pronouncements
In January 2010, the FASB issued ASC Update No. 2010-06, an additional update to the ASC guidance for fair value measurements. The new guidance requires additional disclosures about (1) the different classes of assets and liabilities measured at fair value, (2) the valuation techniques and inputs used, (3) the activity in Level 3 fair value measurements, and (4) the transfers between Levels 1, 2 and 3. The updated guidance is effective for annual and interim periods beginning December 15, 2009, except for the disclosures about the activity in Level 3 fair value measurements, for which the new guidance is effective for fiscal years beginning after December 15, 2010. The Company adopted the provisions that were effective for annual and interim periods beginning December 15, 2009 effective January 1, 2010. The adoption of ASC Update 2010-06 did not have an impact on the Company’s financial position, results of operations or cash flows. Refer to Note 4 for the Company’s disclosures on fair value accounting.
2. Earnings per share
Basic earnings per share of common stock (“EPS”) is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share incorporates the treasury stock method, and is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock and potential common stock equivalents outstanding during the period, if dilutive. Potential common stock equivalents include incremental shares of common stock issuable upon the exercise of stock options and employee stock awards. Income attributable to common stock is calculated as net income less dividends paid on the Series A Preferred Stock. The Company declared and paid cash dividends of $931 and $1,862 ($.5781 per share) on the Series A Preferred Stock for the three and six months ended June 30, 2010 and 2009, respectively.

 

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The following is the calculation of basic and diluted weighted average shares outstanding and earnings per share of common stock for the periods indicated:
                                 
    For the Three Months Ended June 30,     For the Six Months Ended June 30,  
    2010     2009     2010     2009  
Net income (loss)
  $ (889 )   $ (242 )   $ 5,225     $ 765  
Preferred stock dividends
    931       931       1,862       1,862  
 
                       
Income (loss) attributable to common stock
  $ (1,820 )   $ (1,173 )   $ 3,363     $ (1,097 )
 
                       
Weighted average shares:
                               
Weighted average shares — basic
    11,116,476       9,233,725       11,111,092       9,217,902  
Dilution effect of stock options outstanding at the end of period
                       
 
                       
Weighted average shares — diluted
    11,116,476       9,233,725       11,111,092       9,217,902  
 
                       
                                 
Income (loss) per common share:
                               
Basic
  $ (0.16 )   $ (0.13 )   $ 0.30     $ (0.12 )
 
                       
Diluted
  $ (0.16 )   $ (0.13 )   $ 0.30     $ (0.12 )
 
                       
The following options and unvested restricted shares, which could be potentially dilutive in future periods, were not included in the computation of diluted net income per share because the effect would have been anti-dilutive for the periods indicated:
                                 
    For the Three Months Ended June 30,     For the Six Months Ended June 30,  
    2010     2009     2010     2009  
                                 
Anti-dilutive shares
    82,360       87,931       93,529       87,931  
 
                       
3. Derivative Instruments
The Company’s primary market exposure is to adverse fluctuations in the prices of natural gas. The Company uses derivative instruments, primarily forward contracts, costless collars and swaps, to manage the price risk associated with its gas production, and the resulting impact on cash flow, net income, and earnings per share. The Company does not use derivative instruments for speculative purposes.
The Company recognizes its derivative instruments as either assets or liabilities at fair value on its consolidated balance sheet and accounts for the derivative instruments as either cash flow hedges or mark to market derivative instruments. On the cash flow statement, the cash flows from these instruments are classified as operating activities.
Derivative instruments expose the Company to counterparty credit risk. The Company enters into these contracts with third parties and financial institutions that it considers to be creditworthy. In addition, the Company’s master netting agreements reduce credit risk by permitting the Company to net settle for transactions with the same counterparty.
As with most derivative instruments, the Company’s derivative contracts contain provisions which may allow for another party to require security from the counterparty to ensure performance under the contract. The security may be in the form of, but not limited to, a letter of credit, security interest or a performance bond. The Company was in an overall asset position with each of its counterparties at June 30, 2010, and no party in any of its derivative contracts has required any form of security guarantee.
Cash flow hedges
Derivative instruments that are designated and qualify as cash flow hedges are recorded at fair value on the balance sheet and the effective portion of the change in fair value is reported as a component of accumulated other comprehensive income and is subsequently reclassified into the oil and gas sales line on the consolidated statement of income as the contracts settle. As of June 30, 2010, the Company expects approximately $3,340 of unrealized gains, included in its Accumulated Other Comprehensive Income (“AOCI”), to be reclassified into earnings in one year or less, as the contracts settle.

 

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Mark to market hedging instruments
Unrealized gains and losses resulting from derivatives not designated as cash flow hedges are recorded at fair value on the balance sheet and changes in fair value are recognized in the price risk management activities line on the consolidated statement of income currently. Realized gains and losses resulting form the contract settlement of derivatives not designated as cash flow hedges also are recorded in the price risk management activities line on the consolidated statement of income.
The Company had the following commodity volumes under derivative contracts as of June 30, 2010:
                 
Natural Gas forward purchase contracts:   2010     2011  
Volume (MMcf)
    4,048       5,650  
The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of June 30, 2010, presented gross of any master netting arrangements:
                 
Derivatives designated as hedging            
instruments under ASC 815   Balance Sheet Location     Fair Value  
Assets
               
Commodity derivatives
  Assets from price risk management - current   $ 3,340  
 
  Assets from price risk management - long term     3,040  
 
             
Total
          $ 6,380  
 
             
                 
Derivatives not designated as            
hedging instruments under ASC 815   Balance Sheet Location     Fair Value  
 
               
Assets
               
Commodity derivatives
  Assets from price risk management - current   $ 1,085  
 
  Assets from price risk management - long term     228  
 
             
Total
          $ 1,313  
 
             

 

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The before-tax effect of derivative instruments in cash flow hedging relationships on the consolidated statement of income for the three months and six months ended June 30, 2010 and 2009, related to the Company’s commodity derivatives was as follows:
Derivatives Designated as Cash Flow Hedging Instruments under ASC 815
                                 
    Amount of Gain (Loss) Recognized in OCI 1 on Derivatives for  
    Three months ended June 30,     Six months ended June 30,  
    2010     2009     2010     2009  
 
       
Commodity contracts
  $ 791     $ (1,268 )   $ 2,814     $ 2,161  
                                 
    Amount of Gain Reclassified from Accumulated OCI  
Location of Gain Reclassified   into Income  
from Accumulated OCI 1   Three months ended June 30,     Six months ended June 30,  
into Income (effective portion)   2010     2009     2010     2009  
 
       
Oil and gas sales
  $     $ 5,263     $     $ 9,410
                 
    Three and six months ended  
    2010     2009  
Location of Gain Recognized in Income (Ineffective) Portion and Amount Excluded from Effectiveness Testing
    N/A       N/A  
     
1  
Other comprehensive income (“OCI”).
The before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statement of income for the three and six months ended June 30, 2010 and 2009 was as follows:
Derivatives Not Designated as Cash Flow Hedging Instruments under ASC 815 - Commodity Contracts
                                 
    Amount of Gain (Loss) Recognized in Income on Derivatives  
Location of Gain/Loss Recognized   Three months ended June 30,     Six months ended June  
in Income on Derivatives   2010     2009     2010     2009  
 
                               
Price risk management activities
  $ 103     $ (2,152 )   $ 7,925     $ (3,292 )
Refer to Note 4 for additional information regarding the valuation of the Company’s derivative instruments.
4. Fair Value Accounting
The Company records certain of its assets and liabilities on the balance sheet at fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). A three-level valuation hierarchy has been established to allow readers to understand the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:
   
Level 1 — Quoted prices (unadjusted) for identical assets or liabilities in active markets.
 
   
Level 2 — Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; and model-derived valuations whose inputs or significant value drivers are observable.
 
   
Level 3 — Unobservable inputs that reflect the Company’s own assumptions.

 

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The following describes the valuation methodologies the Company uses for its fair value measurements.
Cash and cash equivalents
Cash and cash equivalents include all cash balances and any highly liquid investments with an original maturity of 90 days or less. The carrying amount approximates fair value because of the short maturity of these instruments.
Derivative instruments
The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes.
In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.
At June 30, 2010, the types of derivative instruments utilized by the Company included costless collars and swaps. The natural gas derivative markets are highly active. Although the Company’s cash flow and economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.
Credit facility
The recorded value of the Company’s credit facility approximates fair value as it bears interest at a floating rate.
The following table provides a summary of the fair values of assets measured at fair value. There were no liabilities measured at fair value at June 30, 2010. :
                                 
    Level 1     Level 2     Level 3     Total  
 
                               
Assets
                               
Derivative instruments -
Commodity forward contracts
  $     $ 7,693     $     $ 7,693  
 
                       
Total assets at fair value
  $     $ 7,693     $     $ 7,693  
 
                       
The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the six months ended June 30, 2010.
Asset retirement obligations
The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations.” The income valuation technique is utilized by the Company to determine the fair value of the liability at the point of inception by taking into account 1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third-parties; 2) the economic lives of its properties, which is based on estimates from reserve engineers; 3) the inflation rate; and 4) the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. There were no asset retirement obligations measured at fair value within the accompanying consolidated balance sheets at June 30, 2010.
Concentration of credit risk
Financial instruments which potentially subject the Company to credit risk consist of the Company’s accounts receivable and its derivative financial instruments. Substantially all of the Company’s receivables are within the oil and gas industry, including those from a third-party marketing company. Collectability is dependent upon the financial wherewithal of each individual company as well as the general economic conditions of the industry. The receivables are not collateralized.
At June 30, 2010, the Company’s derivative financial instruments were held with two counterparties. The Company continually reviews the credit-worthiness of its counterparties. The Company’s derivative instruments are part of master netting agreements, which reduces credit risk by permitting the Company to net settle for transactions with the same counterparty.

 

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5. Impairment of Long-Lived Assets
The Company reviews the carrying values of its long-lived assets whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to the estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The impairment analysis performed by the Company may utilize Level 3 inputs. The long-lived assets of the Company, which are subject to periodic evaluation, consist primarily of oil and gas properties and undeveloped leaseholds. The Company did not recognize any impairment charges during the three and six months ended June 30, 2010 and 2009.
6. Compensation Plans
The Company recognized stock-based compensation expense of $220 and $496 during the three and six months ended June 30, 2010, respectively, as compared to $302 and $770 in the three and six months ended June 30, 2009, respectively.
Compensation expense related to stock options is calculated using the Black Scholes valuation model. Expected volatilities are based on the historical volatility of Double Eagle’s stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods and contractual expiration dates. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms.
A summary of stock option activity under the Company’s various stock option plans as of June 30, 2010 and changes during the six months ended June 30, 2010 is presented below:
                                 
                    Weighted-        
            Weighted-     Average        
            Average     Remaining     Aggregate  
            Exercise     Contractual     Intrinsic  
Options:   Shares     Price     Term (in years)     Value  
Outstanding at January 1, 2010
    647,897     $ 15.06       4.7          
Granted
    90,380     $ 4.53                  
Exercised
                             
Cancelled/expired
    (107,362 )   $ 15.04                  
 
                             
Outstanding at June 30, 2010
    630,915     $ 13.54       4.6     $  
 
                       
 
                               
Exercisable at June 30, 2010
    323,035     $ 15.35       3.4     $  
 
                       
The Company measures the fair value of the stock awards based upon the fair market value of its common stock on the date of grant and recognizes the resulting compensation expense ratably over the associated service period, which is generally the vesting term of the stock awards. The Company recognizes these compensation costs net of a forfeiture rate and recognizes the compensation costs for only those shares expected to vest. The Company typically estimates forfeiture rates based on historical experience, while also considering the duration of the vesting term of the award.

 

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Nonvested stock awards as of June 30, 2010 and changes during the six months ended June 30, 2010 were as follows:
                 
            Weighted-  
            Average  
            Grant Date  
Stock Awards:   Shares     Fair Value  
Outstanding at January 1, 2010
    87,448     $ 12.38  
Granted
    30,331     $ 4.60  
Vested
    (26,104 )   $ 5.11  
Forfeited/returned
    (17,241 )   $ 14.78  
 
             
Nonvested at June 30, 2010
    74,434     $ 14.43  
 
             
On May 25, 2010, the stockholders of the Company voted to approve the 2010 Stock Incentive Plan, which provides up to 2,000,000 shares of common stock to be issued under the plan.
As part of the acquisition of Petrosearch, the Company assumed all outstanding warrants to purchase common stock that had been issued by Petrosearch prior to the merger. At June 30, 2010, the Company had two tranches of warrants outstanding; 10,310 warrants with an exercise price of $34.64 that expire November 2010; and 8,660 warrants with an exercise price of $21.25 that expire December 2011. In February 2010, 14,691 warrants with an exercise price of $46.19 expired. The warrants had no intrinsic value at June 30, 2010.
7. Income Taxes
Double Eagle is required to record income tax expense for financial reporting purposes, however the Company does not anticipate any payments of current tax liabilities in the near future due to its net operating loss carryforwards.
The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of June 30, 2010, the Company made no provision for interest or penalties related to uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various states. There are currently no federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue service for tax years before 2005 and for state and local tax authorities for years before 2004. The Company’s tax years of 2004 and forward are subject to examination by federal and state taxing authorities.
8. Credit Facility
At June 30, 2010, the Company had a $75 million revolving line of credit in place with $45 million available for borrowing based on several factors, including its current borrowing base and the commitment levels by participating banks. The credit facility is collateralized by all the assets of the Company. As of June 30, 2010, the balance outstanding of $31.0 million had been used to fund capital expenditures primarily on the Company-operated Catalina Unit expansion and other non-operated projects in the Atlantic Rim in 2008, as well as projects in the Pinedale Anticline in 2008, 2009 and 2010. In February 2010, the Company renegotiated its credit agreement primarily to extend the maturity date of the facility from July 31, 2010 to January 31, 2013. The Company paid approximately $450 in one-time financing fees related to renegotiating this facility.
Borrowings under the revolving line of credit bear interest at the greater of (i) 4.5% or (ii) a daily rate equal to the greater of (a) the Federal Funds rate, plus 0.5%, the Prime Rate or the Eurodollar Rate plus 1%, plus (b) a margin ranging between 1.25% and 2.0% depending on the level of funds borrowed. As of June 30, 2010, the interest rate on the line of credit was 4.5%. For the three months ended June 30, 2010 and 2009, the Company incurred interest expense of $353 and $627, respectively, related to the credit facility and $713 and $927 for the six months ended June 30, 2010 and 2009, respectively. The Company capitalized interest costs of $37 and $343 for the three months ended June 30, 2010 and 2009, respectively, and $87 and $643 for the six months ended June 30, 2010 and 2009, respectively.
Under the facility, the Company is subject to both financial and non-financial covenants. The financial covenants include maintaining (i) a current ratio, as defined in the agreement, of 1.0 to 1.0; (ii) a ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and other non-cash items (“EBITDAX”) to interest plus dividends, of greater than 1.5 to 1.0; and (iii) a funded debt to EBITDAX ratio of less than 3.5 to 1.0. As of June 30, 2010, the Company was in compliance with all financial covenants. If the covenants are violated, and the Company is unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.

 

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In August 2010, the Company amended its credit facility to increase the borrowing availability on the line of credit from $45 million to $55 million. The increase in borrowing availability was supported by existing reserves and the additional reserves acquired through the Company’s asset purchase in the Atlantic Rim in July 2010. There were no modifications made to the interest rate calculation as part of the amendment. Any balance outstanding on the facility continues to mature January 31, 2013. Refer to Note 14 for additional information regarding the Company’s asset purchase subsequent to the date of this report.
9. Acquisition of Petrosearch
On August 6, 2009, the Company acquired 100% of the common and preferred shares of Petrosearch in exchange for approximately 1.8 million shares of Double Eagle common stock, valued at approximately $7.3 million, and cash consideration of $873, for a total purchase price of approximately $8.1 million. Effective with the acquisition, each Petrosearch shareholder received .0433 shares of Double Eagle common stock and $0.0211 for each share of Petrosearch common stock and Petrosearch preferred stock, on an as converted basis, such shareholder held. As result of the merger, Petrosearch became a wholly-owned subsidiary of the Company. Petrosearch is an independent crude oil and natural gas exploration and production company, with properties in Texas and Oklahoma. Petrosearch had approximately $8,606 in cash and cash equivalents at the time of acquisition, which the Company believes enhanced the Company’s financial position and ability to finance its current operations and future developmental projects. The Company’s results of operations include the effect of the Petrosearch acquisition from the closing date.
10. Series A Cumulative Preferred Stock
In 2007, the Company completed a public offering of 1,610,000 shares of 9.25% Series A Cumulative Preferred Stock at a price to the public of $25.00 per share.
Holders of the Series A Preferred Stock are entitled to receive, when and as declared by the Board of Directors, dividends at a rate of 9.25% per annum ($2.3125 per annum per share). The Series A Preferred Stock does not have any stated maturity date and will not be subject to any sinking fund or mandatory redemption provisions, except, under some circumstances upon a Change of Ownership or Control. Except pursuant to the special redemption upon a Change of Ownership or Control, the Company may not redeem the Series A Preferred Stock prior to June 30, 2012. On or after June 30, 2012, the Company may redeem the Series A Preferred Stock for cash at its option, in whole or from time to time in part, at a redemption price of $25.00 per share, plus accrued and unpaid dividends (whether or not earned or declared) to the redemption date. The shares of Series A Preferred Stock are classified outside of permanent equity on the accompanying Consolidated Balance Sheets due to the following redemption provision. Following a Change of Ownership or Control of us by a person or entity, other than by a “Qualifying Public Company,” the Company will be required to redeem the Series A Preferred Stock within 90 days after the date on which the Change of Ownership or Control occurred for cash, at the following price per share, plus accrued and unpaid dividends:
         
Redemption Date on or Before   Redemption Price  
June 30, 2011
  $ 25.25  
June 30, 2012 or thereafter
  $ 25.00  
In the event of liquidation, the holders of the Series A Preferred Stock will have the right to receive $25.00 per share, plus all accrued and unpaid dividends, before any payments are made to the holders of the Company’s common stock.

 

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11. Comprehensive Income (Loss)
The components of comprehensive income (loss) were as follows:
                                 
    For the Three Months Ended June 30,     For the Six Months Ended June 30,  
    2010     2009     2010     2009  
Net income (loss) attributable to common stock
  $ (1,820 )   $ (1,173 )   $ 3,363     $ (1,097 )
Change in derivative instrument fair value, net of tax expense1
    511       (1,268 )     1,763       2,161  
Reclassification to earnings
          (5,263 )           (9,410 )
 
                       
Comprehensive income (loss)
  $ (1,309 )   $ (7,704 )   $ 5,126     $ (8,346 )
 
                       
     
(1)  
The change in derivative instrument fair value is net of tax totaling $280 and $0 for the three months ended June 30, 2010 and 2009, respectively. The change in derivative instrument fair value is net of tax totaling $1,051 and $0 for the six months ended June 30, 2010 and 2009, respectively.
The components of accumulated other comprehensive income were as follows:
                 
    June 30,     December 31,  
    2010     2009  
Net change in derivative instrument fair value, net of tax benefit of $2,300 and $1,249
  $ 4,080     $ 2,317  
 
           
Total accumulated other comprehensive gain, net
  $ 4,080     $ 2,317  
 
           
12. Cash Held in Escrow
The Company has received deposits representing partial prepayments of the expected capital expenditures from third party working interest owners in the Table Top Unit #1 exploration project. The unexpended portion of the deposits at June 30, 2010 and December 31, 2009 totaled $613 and $611, respectively.
13. Contingencies
Legal proceedings
From time to time, the Company is involved in various legal proceedings, including the matters discussed below. These proceedings are subject to the uncertainties inherent in any litigation. The Company is defending itself vigorously in all such matters, and while the ultimate outcome and impact of any proceeding cannot be predicted with certainty, management believes that the resolution of any proceeding will not have a material adverse effect on the Company’s financial condition or results of operations.
The Company, along with other plaintiffs, filed a lawsuit on August 24, 2007, in the District Court of Fremont County, Wyoming, against Conoco/Phillips and other defendants who own working interests in the Madden Deep Unit. The Company and the other plaintiffs in the case are asserting that, under the gas balancing agreement, they are entitled to receive either monetary damages or their respective shares of the natural gas produced from the Madden Deep Unit over at least the period February 1, 2002 through June 30, 2007. For the period from November 1, 2006 through June 30, 2007, the Company has recognized the sales and has recorded a related account receivable of $292, net of allowance for uncollectible amounts. Subsequent to June 2007, the Company continued to recognize sales for its share of production and has consistently collected on the receivables due. As of June 30, 2010, the Company has not recognized any amount of sales proceeds for the period February 1, 2002 through October 30, 2006. Sulfur sales are not subject to a gas balancing agreement, and, accordingly, the Company received the proceeds for its share of sulfur sales dating back to February 2002 and has continued to receive its respective share on an on-going basis. Subsequent to the end of the second quarter, the Company signed a settlement agreement with many of the defendants in the lawsuit, in which the Company will receive approximately $4.0 million. The Company expects to receive the settlement in the third quarter of 2010. The Company’s results for the second quarter 2010 do not include an accrual for this amount.
On December 18, 2009, Tiberius Capital, LLC (“Plaintiff”), a stockholder of Petrosearch Energy Corporation (“Petrosearch”) prior to the Company’s acquisition (the “Acquisition”) of Petrosearch pursuant to a merger between Petrosearch and a wholly-owned subsidiary of the Company, filed a claim in the US District Court of New York against Petrosearch, the Company, and the individuals who were officers and directors of Petrosearch prior to the Acquisition. In general, the claims against the Company and Petrosearch are that Petrosearch inappropriately denied dissenters’ rights of appraisal under the Nevada Revised Statutes to its stockholders in connection with the Acquisition, that the defendants violated various sections of the Securities Act of 1933 and the Securities Exchange Act of 1934, and that the defendants caused other damages to the stockholders of Petrosearch. The Plaintiff is seeking monetary damages. The Company does not believe the case has merit, and intends to defend this case vigorously.

 

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14. Subsequent Events
In July 2010, the Company reached a settlement agreement with many of the defendants in the outstanding Madden Deep Unit lawsuit that has been ongoing since 2007. The Company had sought to recover payment for natural gas produced from its interest in the Madden Deep Unit between the period February 1, 2002 through June 30, 2007. In accordance with the agreement, the Company is expected to receive cash proceeds of approximately $4.0 million in the third quarter of 2010.
On July 20, 2010, the Company signed an asset purchase agreement with a third party to purchase certain assets in the Atlantic Rim. The table below shows the working interest acquired under the terms of the Purchase and Sale Agreements and the Company’s total ownership upon completion of the transaction in each of the units within the Atlantic Rim:
                 
            Post Acquisition Working  
Unit   Working Interest Acquired     Interest Percentage  
Catalina
    3.08 %     72.40 %
Sun Dog
    12.60 %     21.54 %
Doty Mountain
    1.15 %     18.00 %
The effective date of the transaction is January 1, 2010. The total cost of the asset purchase transaction was $8.4 million, subject to closing adjustments. The total cash paid by the Company, subject to post closing adjustments, was $7.8 million, net of revenue, expense and capital costs incurred from the effective date through the closing date.
Effective August 5, 2010, the Company amended its credit facility to increase the borrowing availability on the line of credit from $45 million to $55 million. The increase in borrowing availability was supported by existing reserves and the additional reserves acquired through the Company’s asset purchase in the Atlantic Rim in July 2010, as discussed above. There were no modifications made to the interest rate calculation as part of the amendment. Any balance outstanding on the facility matures on January 31, 2013.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The terms “Double Eagle”, “Company”, “we”, “our”, and “us” refer to Double Eagle Petroleum Co. and its subsidiaries, as a consolidated entity, unless the context suggests otherwise. Unless the context suggests otherwise, the amounts set forth in Part I and Part II herein are in thousands, except units of production, ratios, share or per share amounts.
FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation the Risk Factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2009, including the following:
   
A decline in oil or gas prices;
   
The changing political environment in which we operate;
   
Our ability to maintain adequate liquidity in connection with low oil and gas prices;
   
Our ability to obtain, or a decline in, oil or gas production;
   
Our ability to continue to develop our Atlantic Rim project;
   
Our ability to increase our natural gas and oil reserves;

 

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Incorrect estimates of required capital expenditures;
   
The amount and timing of capital deployment in new investment opportunities;
   
The volumes of production from our oil and gas development properties, which may be dependent upon issuance by federal, state, and tribal governments, or agencies thereof, of drilling, environmental and other permits, and the availability of specialized contractors, work force, and equipment;
   
Our future capital requirements and availability of capital resources to fund capital expenditures;
   
Our ability to successfully integrate and profitably operate any future acquisitions;
   
Increases in the cost of drilling, completion and gas collection or other costs of production and operations;
   
The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge;
   
Numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and actual future production rates and associated costs;
   
Our ability to remedy any deficiencies that may be identified in the review of our internal controls;
   
The credit worthiness of third-parties which we enter into business agreements with;
   
General economic conditions, tax rates or policies, interest rates and inflation rates;
   
Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment;
   
Weather, climate change and other natural phenomena;
   
Industry and market changes, including the impact of consolidations and changes in competition;
   
The effect of accounting policies issued periodically by accounting standard-setting bodies;
   
The actions of third party co-owners of interests in properties in which we also own an interest;
   
The cost and effects on our business, including insurance, resulting from terrorist actions or natural disasters and responses to such actions or events;
   
The volatility of our stock price; and
   
The outcome of any current or future litigation or similar disputes and the impact on any such outcome or related settlements.
We also may make material acquisitions or divestitures or enter into financing transactions. None of these events can be predicted with certainty and the possibility of their occurring is not taken into consideration in the forward-looking statements.
New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward -looking statements, whether as a result of new information, future events, or otherwise.
Business Overview and Strategy
We are an independent energy company engaged in the exploration, development, production and sale of natural gas and crude oil, primarily in Rocky Mountain Basins of the western United States. Double Eagle was incorporated in the State of Wyoming in January 1972 and reincorporated in the State of Maryland in February 2001. From 1995 to 2006, our common shares were publicly traded on the NASDAQ Capital Market under the symbol “DBLE”. On December 15, 2006, our common shares began trading on the NASDAQ Global Select Market. Our Series A Cumulative Preferred Stock (“Preferred Stock”) was issued on the NASDAQ Capital Market, under the symbol “DBLEP” on July 3, 2007. It began trading under the symbol “DBLEP” on the NASDAQ Global Select Market on September 30, 2007. Our corporate offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, telephone number (303) 794-8445. Our website is www.dble.com.
Our objective is to increase long-term stockholder value by implementing our corporate strategy of economically growing our reserves and production through the development of our existing core properties, partnering on selective exploration projects, and pursuing strategic acquisitions that expand or complement our existing operations. Our operations are currently focused on two core properties located in southwestern Wyoming, where we have coal bed methane reserves and production in the Atlantic Rim area of the Eastern Washakie Basin, and tight sands gas reserves and production in the Pinedale Anticline. The operations in the Pinedale Anticline and Atlantic Rim operate under federal exploratory unit agreements between the working interest partners. Unitization is a type of sharing arrangement by which owners of operating and non-operating working interests pool their property interests in a producing area to form a single operating unit. Units are designed to improve efficiency and economics of developing and producing an area. The share that each interest owner receives is based upon the respective acreage contributed by each owner in the participating area (“PA”) that surround the producing wells as a percentage of the entire acreage of the PA. This PA, and the associated working interest, will change as more wells and acreage are added to the PA.

 

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Following are summary comments of our performance in several key areas during the three and six months ended June 30, 2010:
   
Average Daily Production
During the three months ended June 30, 2010, our total average daily net production decreased 6% to 24,697 Mcfe as compared to average daily net production of 26,209 Mcfe during the same prior-year period. Total average daily net production decreased 4% to 24,802 in the first six months of 2010, as compared to 25,777 Mcfe in the first half of 2009. The changes in production by major operating area are discussed below.
Atlantic Rim. During the three months ended June 30, 2010, average daily net production at the Atlantic Rim decreased 11% to 17,565 Mcfe, as compared to 19,724 Mcfe during the three months ended June 30, 2009. Average daily net production at our Catalina Unit decreased 16% to 14,531 Mcfe, as compared to 17,283 Mcfe during the same prior-year period. The decrease was due in part to the continuation of our well enhancement program that began in the third quarter of 2009, which requires wells to be temporarily off-line. Additionally, we continue to reconfigure our compressors in an effort to maximize well performance by reducing suction pressure at the well head, which is ultimately expected to increase the output from each well. Lastly, the Catalina field experienced several power outages during the period, which temporarily halted production, and the Southern Star pipeline was shut down for maintenance for several days in April 2010. Average daily production, net to our interest, at the Sun Dog and Doty Mountain Units increased 24% to 3,034 Mcfe, as compared to average daily net production of 2,441 Mcfe during the three months ended June 30, 2009. The increase was primarily due to the additional compression capacity added at the Doty Mountain Unit in the first quarter of 2010 and increased production from well stimulations in the Sun Dog Unit.
Average daily net production at the Atlantic Rim decreased 5% to 17,911 Mcfe in the six months ended June 30, 2010, as compared to 18,766 Mcfe during the same prior-year period. During the six months ended June 30, 2010, average daily net production at our Catalina Unit decreased 12% to 15,062 Mcfe, as compared to 16,935 Mcfe during the same prior-year period. As discussed above, the overall decrease in production at the Atlantic Rim and within the Catalina Unit was driven by the continued compression reconfiguration project and continuation of our well enhancement program. For the six months ended June 30, 2010, average daily net production at the Sun Dog and Doty Mountain units increased 56% to 2,849 Mcfe, as compared to 1,831 Mcfe in the six months ended June 30, 2009.
Pinedale Anticline. Average daily net production at the Pinedale Anticline decreased 2% to 5,053 Mcfe for the three months ended June 30, 2010, as compared to 5,153 Mcfe in same the 2009 period. The production at the Mesa Unit includes production from eight new wells; however, management believes that the overall production decline at the Mesa Units is related to the operator managing the production flow from the field due to the low gas prices in the Rocky Mountain region.
During the six months ended June 30, 2010, average daily net production at the Pinedale Anticline decreased 11% to 5,034 Mcfe, as compared to 5,648 Mcfe in the six months ended June 30, 2009.
Madden Deep Unit. During the three and six months ended June 30, 2010, our average daily net production at the Madden Deep Unit was 1,029 Mcfe and 808 Mcfe, respectively, as compared to 513 Mcfe and 451 Mcfe in the three and six months ended June 30, 2009, respectively. The increase was due to a one-time gas balancing adjustment.
   
Oil and Gas Sales
During the three months ended June 30, 2010, net oil and gas sales decreased 27% to $7,608, as compared to $10,492 during the same 2009 period. The decrease was due in part to the decrease in production volumes discussed above, but also due to a lower realized gas price during the period. In addition, during the three months ended June 30, 2010, our average gas price realized decreased 8%, to $3.99 from $4.34 in the comparable 2009 period. Although the average CIG index price was approximately 50% higher during the three months ended June 30, 2010, our realized gas price was lower in 2010 due to the strength of our hedges in 2009. During the three months ended June 30, 2009, our derivative instrument settlements totaled $5,263, all of which was classified as oil and gas sales on the consolidated statement of operations. In comparison, in 2010, our derivative instrument settlements totaled $1,666, but were classified as price risk management activities on the consolidated statement of operations due to the accounting treatment of these instruments.

 

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For the six months ended June 30, 2010, oil and gas sales decreased 11% to $18,657, as compared to the same prior-year period. The decrease was due both to the lower production volumes discussed below, as well as a decrease in our average realized gas price. Our average realized gas price for the six months ended June 30, 2010 decreased 15%, to $4.34 from $5.10 during the six months ended June 30, 2009. Although the average CIG index price was approximately 53% higher for the six months ended June 30, 2010, our realized gas price was lower in 2010 due to the strength of our hedges in 2009. During the six months ended June 30, 2009, our derivative instrument settlements totaled $12,336, of which $9,410 was classified as oil and gas sales on the consolidated statement of operations. In comparison, in 2010, our derivative instrument settlements totaled $1,443 during the first six months of 2010, but were classified as price risk management activities on the consolidated statement of operations due to the accounting treatment of these instruments.
OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY
Liquidity and Capital Resources
We believe that we have sufficient liquidity and capital resources to continue our long-term strategic plan, including our 2010 capital program (see Capital Requirements below). We intend to use capital resources made available from future operating cash flow and through our $75 million credit facility ($55 million credit availability), to fund this activity. We also may consider additional offerings of securities. Although we believe that we would be able to secure additional financing if required, we can provide no assurance that we will be able to do so or what the terms of any additional financing would be.
Information about our financial position is presented in the following table:
                 
    June 30,     December 31,  
    2010     2009  
 
               
Financial Position Summary
               
Cash and cash equivalents
  $ 4,192     $ 5,682  
Working capital
  $ 7,110     $ (4,067 )
Balance outstanding on credit facility
  $ 31,000     $ 34,000  
Stockholders’ equity and preferred stock
  $ 90,321     $ 84,696  
 
               
Ratios
               
Debt to total capital ratio
    25.6 %     28.6 %
Total debt to equity ratio
    59.2 %     72.8 %
During the six months ended June 30, 2010, our working capital increased to $7,110 compared to negative working capital of $(4,067) at December 31, 2009. The higher working capital is primarily the result of an increase in the fair value of our derivative contracts expected to settle within one year. Based on changes in the expected commodity prices, certain derivative contracts moved from a current liability position at December 31, 2009 to a current asset position at June 30, 2010. In addition, our accounts payable and accrued liabilities balance decreased $4,791 from December 31, 2009, primarily due to a slowdown in work-over and drilling activity at our non-operated properties and due to timing of production tax payments.

 

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Cash flow activities
The table below summarizes our cash flows for the six months ended June 30, 2010 and 2009, respectively:
                 
    Six months ended June 30,  
    2010     2009  
    (unaudited)  
Cash provided by (used in):
               
Operating activities
  $ 10,718     $ 16,826  
Investing activities
    (7,084 )     (28,650 )
Financing activities
    (5,124 )     15,722  
 
           
Net change in cash
  $ (1,490 )   $ 3,898  
 
           
During the six months ended June 30, 2010, net cash provided by operating activities was $10,718, compared to $16,826 in the same prior-year period. The primary sources of cash during the six months ended June 30, 2010 were $5,225 of net income, which was net of non-cash charges of $9,125 related to depreciation, depletion, and amortization expenses (“DD&A”) and accretion expense, and non-cash stock-based compensation expense of $496. In addition, we had an increase in accrued production taxes of $667 and an increase of $2,945 in the provision for deferred income taxes. These increases were partially offset by the non-cash gain on derivative contracts of $6,482.
During the six months ended June 30, 2010, net cash used in investing activities was $7,084, as compared to $28,650 in the same prior-year period. Drilling activity slowed significantly in 2009 and the first half of 2010, and as a result, our cash outflow related to capital expenditures also decreased as compared to the prior year. The capital expenditures in the first six months of 2010 primarily related to non-operated drilling in the Pinedale Anticline, whereas in the first six months of 2009, the Company had significant cash outflow related to the 2008 drilling programs in the Atlantic Rim and Pinedale Anticline.
During the six months ended June 30, 2010, we had net cash used by financing activities of $5,124, as compared to net cash provided by financing activities of $15,722 in the same prior-year period. In the first quarter of 2009, we had significant draws on our credit facility to fund costs incurred in the drilling program in the fourth quarter of 2008. In contrast, we were able to repay $3,000 on our credit facility in the first six months of 2010 due to increased operating cash flow and slower drilling and workover activity. We also expended cash to make the first and second quarter dividend payments totaling $1,862. Dividends are expected to continue to be paid on a quarterly basis on the Series A Preferred Stock in the future at a rate of $931 per quarter.
Off-Balance Sheet Arrangements
We do not participate in transactions that generate relationships with unconsolidated entities or financial partnerships. Such entities are often referred to as structured finance or special purpose entities (“SPEs”) or variable interest entities (“VIEs”). SPEs and VIEs can be established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. We were not involved in any unconsolidated SPEs or VIEs at any time during any of the periods presented in this Form 10-Q.
From time to time, we enter into contracts that might be construed as off-balance sheet obligations but are normal in the day-to-day course of business in the oil and gas industry. Those contracts are the derivative instruments discussed in “Contracted Volumes” below. We do not believe we will be affected by these contracts materially differently than other similar companies in the energy industry.
Line of Credit
As of June 30, 2010, the Company had a $75 million credit facility in place, with borrowing availability of $45 million, collateralized by our oil and gas properties and other assets. Any balance outstanding on the credit facility matures January 31, 2013.
In August 2010, we amended our credit facility to increase the borrowing availability on the line of credit from $45 million to $55 million. The increase in borrowing availability was supported by existing reserves and the additional reserves acquired through our asset purchase in the Atlantic Rim in July 2010. There were no modifications made to the interest rate calculation as part of the amendment. Any balance outstanding on the facility continues to mature January 31, 2013.

 

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As of June 30, 2010, the outstanding balance on our credit facility was $31.0 million. Subsequent to the quarter end, we drew down an additional $6.0 million to partially finance the Atlantic Rim interest acquisition. The interest rate as of June 30, 2010, calculated in accordance with the agreement, was 4.5%, compared to an interest rate between 4.5% and 6.75% at June 30, 2009.
We incurred interest expense related to the credit facility of $353 and $627, for the three months ended June 30, 2010 and 2009, respectively, and $713 and $927 for the six months ended June 30, 2010 and 2009, respectively. The Company capitalized interest costs of $37 and $343 for the three months ended June 30, 2010 and 2009, respectively, and $87 and $643 for the six months ended June 30, 2010 and 2009, respectively.
We are subject to certain financial and non-financial covenants with respect to the above credit facility, including requirements to maintain (i) a current ratio, as defined in the agreement, of at least 1.0 to 1.0; (ii) a ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and other non-cash items (“EBITDAX”) to interest plus dividends, of greater than 1.5 to 1.0; and (iii) a funded debt to EBITAX ratio of less than 3.5 to 1.0. As of June 30, 2010, we were in compliance with all covenants under the facility. If any of the covenants are violated, and the Company is unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.
Our borrowing base is subject to redetermination each June 15 and December 15. As of June 15, 2010, our borrowing base was in excess of our current borrowing availability.
Capital Requirements
Our estimated capital budget for 2010 is approximately $15-$20 million for drilling up to eight wells within the Catalina Unit, and ongoing non-operated development programs on the Pinedale Anticline and within the Sun Dog and Doty Mountain Units. The 2010 budget does not include the impact of any potential future exploration projects, or ongoing exploration or development activities or potential acquisitions. It also does not include the asset acquisition of additional working interest in the Atlantic Rim in July 2010. We expect to fund our 2010 capital expenditures with cash provided by operating activities and funds made available through our credit facility. We may find it necessary in the future to raise additional funds through private placements or registered offerings of equity or debt.
Contractual Obligations
The impact that our contractual obligations as of June 30, 2010 are expected to have on our liquidity and cash flows in future periods is:
                                         
            One year     2 - 3     4 - 5     More than  
    Total     or less     Years     Years     5 Years  
Credit facility (a)
  $ 31,000     $     $ 31,000     $     $  
Interest on line of credit (b)
    3,662       1,414       2,248              
Capital leases
    1,128       752       376              
Operating leases
    8,193       2,349       5,154       666       24  
 
                             
Total contractual cash commitments
  $ 43,983     $ 4,515     $ 38,778     $ 666     $ 24  
 
                             
     
(a)  
The amount listed reflects the balance outstanding as of June 30, 2010. Any balance outstanding on our credit facility at January 31, 2013, will be due at that time.
 
(b)  
Assumes the interest rate on our credit facility is consistent with that of June 30, 2010.

 

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RESULTS OF OPERATIONS
Three months ended June 30, 2010 compared to the three months ended June 30, 2009
Oil and gas sales volume and price comparisons
                                                 
    Three Months Ended June 30,     Percent     Percent  
    2010     2009     Volume     Price  
Product:   Volume     Average Price     Volume     Average Price     Change     Change  
Gas (Mcf)
    2,212,115     $ 3.99       2,342,787     $ 4.34       -6 %     -8 %
Oil (Bbls)
    5,892     $ 75.00       7,039     $ 46.03       -16 %     63 %
Mcfe
    2,247,466     $ 4.13       2,385,021     $ 4.40       -6 %     -6 %
Our average gas price realized for the three months ended June 30, 2010 is calculated by summing 1) production revenue received from third parties for sale of our gas, which is included in the oil and gas sales line item on the consolidated statement of income; 2) settlement of our cash flow hedges included within oil and gas sales on the consolidated statement of income; and 3) realized gain/(loss) on our economic hedges, which is included in our price risk management activities line on the consolidated statement of income, totaling $1,666 and $0, for the three months ended June 30, 2010 and 2009, respectively. This amount is divided by the total Mcfe volume for the period.
For the three months ended June 30, 2010, total net production decreased 6% to 2,247 MMcfe, as compared to the three months ended June 30, 2009. The decrease is due to lower production volumes at the Catalina Unit and Mesa Units, as discussed below.
During the three months ended June 30, 2010, our total average daily net production at the Atlantic Rim decreased 11% to 17,565 Mcfe, as compared to 19,724 Mcfe during the same prior-year period. Average daily net production at our Catalina Unit decreased 16% to 14,531 Mcfe, as compared to 17,283 Mcfe during the three months ended June 30, 2009. Several circumstances during the second quarter of 2010 led to the decline in production in the Atlantic Rim and at the Catalina Unit. During the second quarter, we continued to make adjustments to our gas compressors, in an effort to maximize well performance by reducing suction pressure at the well head. This is ultimately expected to increase the output from the field. In addition, the field was struck by several power outages during the period, which temporarily shut down production and the Southern Star pipeline was shut down for maintenance for several days in April. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 24% to 3,034 Mcfe, as compared to average daily net production of 2,441 during the same prior-year period. The increase was primarily due to the additional compression capacity added at the Doty Mountain Unit in the first quarter of 2010 and increased production from well stimulations in the Sun Dog Unit. The operator of the Sun Dog and Doty Mountain units has informed us that they plan to work over an additional 36 wells in the third and fourth quarters of 2010, and add additional injection capacity in the Sun Dog Unit.
Average daily net production in the Pinedale Anticline decreased 2% during the three months ended June 30, 2010, to 5,053 Mcfe, as compared to 5,153 Mcfe in the same prior-year period. Although the operator brought eight new wells on-line for production during the quarter, production declined as compared to the prior year. Management believes that this production decline at the Mesa Units is related to the operator managing the production flow from the field due to the low gas prices in the Rocky Mountain region. The operator at the Mesa Units has informed us that it is in process of drilling approximately eight additional wells, which are expected to come on-line in the third and fourth quarters of 2010.
During the three months ended June 30, 2010, the average daily net production at the Madden Unit increased to 1,029 Mcfe compared to 513 Mcfe in the same prior-year period. The increase was related to one-time gas balancing adjustments.
For the three months ended June 30, 2010, oil and gas sales decreased 27% to $7,608, due in part to the decrease in production volumes discussed above. In addition, during the three months ended June 30, 2010, our average realized gas price decreased 8%, to $3.99 from $4.34 in the comparable 2009 period. Although the average CIG index price was approximately 50% higher during the three months ended June 30, 2010, our realized gas price was lower in 2010 due to the strength of our hedges in 2009. During the three months ended June 30, 2009, our derivative instrument settlements totaled $5,263, all of which was classified as oil and gas sales on the consolidated statement of operations. In comparison, in 2010, our derivative instrument settlements totaled $1,666, but were classified as price risk management activities on the consolidated statement of operations due to the accounting treatment of these instruments.

 

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Transportation and gathering revenue
During the three months ended June 30, 2010, transportation and gathering revenue decreased 11% to $1,401 from $1,583 for the three months ended June 30, 2009. The Company receives fees for gathering and transporting third-party gas through our intrastate gas pipeline, which connects the Catalina Unit with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc. The decrease in revenue is consistent with the decrease in production volumes at the Catalina Unit discussed above.
Price risk management activities
We recorded a net gain on our derivative contracts not designated as cash flow hedges of $103 for the three months ended June 30, 2010, as compared to a loss of $(2,152) during the same prior year period. The net gain on price risk management activities during the period consisted of an unrealized non-cash loss of $1,563, which represents a change in the fair value of our mark-to-market derivative instruments from December 31, 2009 to June 30, 2010, and a net realized gain of $1,666 related to the settlements of certain of our economic hedges.
Oil and gas production expenses, production taxes, depreciation, depletion and amortization
                 
    Three Months Ended June 30,  
    2010     2009  
    (in dollars per Mcfe)  
Average price
  $ 4.13     $ 4.40  
 
               
Production costs
    1.07       0.83  
Production taxes
    0.45       0.32  
Depletion and amortization
    1.97       1.93  
 
           
Total operating costs
    3.49       3.08  
 
           
 
               
Gross margin
  $ 0.64     $ 1.32  
 
           
Gross margin percentage
    15 %     30 %
 
           
Production costs, on a dollars per Mcfe basis, is calculated by dividing production costs, as stated on the consolidated statement of operations, by total production volumes during the period. This calculation excludes certain gathering costs incurred by the Company’s subsidiary, Eastern Washakie Midstream, which are eliminated in consolidation. During the three months ended June 30, 2010, well production costs increased 21% to $2,397, as compared to $1,989 during the same prior-year period, and production costs in dollars per Mcfe increased 29%, or $0.24, to $1.07, as compared to the same prior-year period. The increase in production costs in total, and on a per Mcfe basis, is primarily due to higher workover costs related to the well enhancement program at the Catalina Unit, higher transportation costs at the Madden Unit and also production costs added from the Petrosearch properties, which were not included in the second quarter 2009 results.
During the three months ended June 30, 2010, production taxes increased 34% to $1,010, as compared to $753 in the three months ended June 30, 2009, and production taxes, on a dollars per Mcfe basis, decreased 41%, or $0.13 to $0.45, as compared to the same prior-year period. The Company is required to pay taxes on the proceeds received upon the sale of our gas to counterparties. As the gas market prices rise, less of our revenue is related to cash received from the settlement of the financial derivative instruments we have in place; rather it is generated by the cash received for the physical sale of our gas in the open market. The decrease in cash received from derivative settlements in 2010 resulted in an overall increase in production taxes, as well as an increase of production taxes expressed on a dollars per Mcfe basis.
Depreciation, depletion, and amortization (“DD&A”) for the three months ended June 30, 2010 decreased 4% to $4,530, as compared to $4,715 in the same prior-year period, and depletion and amortization related to producing assets decreased 2% to $4,428, as compared to $4,598 in the same prior-year period. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 2%, or $0.04 to $1.97, as compared to the same prior-year period.

 

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Pipeline operating costs
During the three months ended June 30, 2010, pipeline operating costs decreased 11% to $971 from $1,087 for the three months ended June 30, 2009.
General and administrative expenses
General and administrative expenses decreased 2% to $1,392 for the three months ended June 30, 2010, as compared to $1,427 for the three months ended June 30, 2009. Our general and administrative expenses were lower in the three months ended June 30, 2010 due primarily to $123 of expenses that were incurred in the second quarter of 2009 related to the acquisition of Petrosearch Energy Corporation. In addition, stock-based compensation decreased by approximately $82 due the forfeitures of stock awards by two executive officers that terminated during the quarter. These decreases were offset by an increase in non-merger related legal expenses and building rent expense assumed as part of the Petrosearch acquisition.
Income taxes
We recorded an income tax benefit of $512 during the three months ended June 30, 2010, as compared to an income tax benefit of $110 during the same prior-year period. Our effective tax rate for the second quarter of 2010 was 36.0% compared to 40.5% for the second quarter of 2009. The rate was lower in the 2010 period due to a reduction in permanent income tax differences related to stock option expense and higher projected net income. Although we expect to continue to generate losses for federal income tax reporting purposes, our operations have resulted in a deferred tax position required under generally accepted accounting principles. We expect to recognize deferred income tax expense on taxable income for the remainder of 2010 at an expected federal and state rate of approximately 35.0%.
Six months ended June 30, 2010 compared to the six months ended June 30, 2009
Oil and gas sales volume and price comparisons
                                                 
    Six Months Ended June 30,     Percent     Percent  
    2010     2009     Volume     Price  
Product:   Volume     Average Price     Volume     Average Price     Change     Change  
Gas (Mcf)
    4,412,125     $ 4.34       4,577,202     $ 5.10       -4 %     -15 %
Oil (Bbls)
    12,828     $ 73.07       14,736     $ 38.25       -13 %     91 %
Mcfe
    4,489,091     $ 4.47       4,665,618     $ 5.12       -4 %     -13 %
Our average gas price realized for the six months ended June 30, 2010 is calculated by summing 1) production revenue received from third parties for sale of our gas, which is included in the oil and gas sales line item on the consolidated statement of operations, 2) settlement of our cash flow hedges included within oil and gas sales on the consolidated statement of operations and 3) realized gain/loss on our economic hedges, which is included in our price risk management activities line on the consolidated statement of operations, totaling $1,443 and $2,926, for the six months ended June 30, 2010 and 2009, respectively. This amount is divided by the total Mcfe volume for the period.
For the six months ended June 30, 2010, total net production decreased 4% to 4,489 MMcfe, as compared to the six months ended June 30, 2009. The decrease is due to lower production volumes at the Catalina Unit and Mesa Units, as discussed below.
During the six months ended June 30, 2010, average daily net production at the Atlantic Rim decreased 5% to 17,911 Mcfe, as compared to 18,766 Mcfe during the same prior-year period. The decrease in Atlantic Rim production was driven by lower production volumes at the Catalina Unit, where the average daily net production decreased 12% to 15,062 Mcfe, as compared to 16,935 Mcfe during the same period of 2009. The decrease was due in part to the continuation of our well-enhancement program, which began in the third quarter of 2009. This program requires individual wells to be off-line for short periods of time while the well is worked-over. In addition, we began reconfiguring our compressors in March 2010 in an effort to maximize well performance by reducing suction pressure at the well head, which is ultimately expected to increase the output from each well. Finally, in the second quarter of 2010, the Catalina field experienced several power outages, which temporarily shut down production. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 56% to 2,849 Mcfe, as compared to average daily net production of 1,831 Mcfe during the same prior-year period. The increase was primarily due to the additional compression capacity added at the Doty Mountain Unit in the first quarter of 2010 and increased production from well stimulations in the Sun Dog Unit.

 

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Average daily net production in the Pinedale Anticline decreased 11% during the six months ended June 30, 2010, to 5,034 Mcfe, as compared to 5,648 Mcfe in the same prior-year period. The operator of the Mesa Units brought an additional eight wells on-line during the second quarter of 2010, although this did not result in an overall increase in production. Management believes that the production decline is due to the operator managing the production flow from the field due to the low gas prices in the Rocky Mountain region. The operator at the Mesa Units has informed us that it is in the process of drilling approximately eight additional wells, which are expected to come on-line in the third and fourth quarters of 2010.
During the six months ended June 30, 2010, the average daily net production at the Madden Unit increased 79% to 808 Mcfe, as compared to 451 Mcfe in the same prior-year period. The increase is due to a one-time gas balancing adjustment in the second quarter of 2010.
For the six months ended June 30, 2010, oil and gas sales decreased 11% to $18,657, as compared to the same prior-year period. The decline in oil and gas sales was due in part to the decrease in production volumes discussed above. In addition, during the six months ended June 30, 2010, our average realized gas price decreased 15%, to $4.34 from $5.10 during the six months ended June 30, 2009. Although the average CIG index price was approximately 53% higher during the three months ended June 30, 2010, our realized gas price was lower in 2010 due to the strength of our hedges in 2009. During the six months ended June 30, 2009, our derivative instrument settlements totaled $12,336, of which $9,410 was classified as oil and gas sales on the consolidated statement of operations. In comparison, in 2010, our derivative instrument settlements totaled $1,443, but were classified as price risk management activities on the consolidated statement of operations due to the accounting treatment of these instruments.
Transportation and gathering revenue
During the six months ended June 30, 2010, transportation and gathering revenue decreased 9% to $2,889 from $3,170. The Company receives fees for gathering and transporting third-party gas through our intrastate gas pipeline, which connects the Catalina Unit with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc. The decrease in revenue was driven by lower pipeline throughput from the Catalina Unit.
Price risk management activities
We recorded a net gain on our derivative contracts not designated as cash flow hedges of $7,925 for the six months ended June 30, 2010, as compared to a loss of $3,292 for the six months ended June 30, 2009. This net gain for the 2010 period consists of a net realized gain of $1,443 related to the settlement of our economic hedges, and an unrealized gain of $6,482, which represents the change in fair value of our outstanding mark-to-market derivative instruments from December 31, 2009 to June 30, 2010.
Oil and gas production expenses, production taxes, depreciation, depletion and amortization
                 
    Six Months Ended June 30,  
    2010     2009  
    (in dollars per Mcfe)  
Average price
  $ 4.47     $ 5.12  
 
               
Production costs
    0.97       0.77  
Production taxes
    0.51       0.35  
Depletion and amortization
    1.97       1.90  
 
           
Total operating costs
    3.45       3.02  
 
           
 
               
Gross margin
  $ 1.02     $ 2.10  
 
           
Gross margin percentage
    23 %     41 %
 
           
Production costs, on a dollars per Mcfe basis, is calculated by dividing production costs, as stated on the consolidated statement of operations, by total production volumes during the period. This calculation excludes certain gathering costs incurred by the Company’s subsidiary, Eastern Washakie Midstream, which are eliminated in consolidation. During the six months ended June 30, 2010, well production costs increased 20% to $4,339, as compared to $3,601 during the same prior-year period, and production costs in dollars per Mcfe increased 26%, or $0.20 to $0.97, as compared to the same 2009 period. A number of factors contributed to the increase in both the total production costs and production costs on a per Mcfe basis, including higher workover costs related to the well enhancement program at the Catalina Unit, higher workover expense at the Sun Dog and Doty Mountain units, an increase in the number of producing wells at the Mesa Units, higher transportation costs at the Madden Unit, and production costs added from the Petrosearch properties, which were not included in the second quarter 2009 results.

 

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During the six months ended June 30, 2010, production taxes increased 41% to $2,309, as compared to $1,642 in the six months ended June 30, 2009, and production taxes, on a dollars per Mcfe basis, increased 46%, or $0.16 to $0.51, as compared to the same prior-year period. The Company is required to pay taxes on the proceeds received upon the sale of our gas to counterparties. As the gas market prices rise, less of our revenue is related to cash received from the settlement of the financial derivative instruments we have in place; rather it is generated by the cash received for the physical sale of our gas in the open market. The decrease in cash received from derivative settlements in 2010 resulted in an overall increase in production taxes, as well as an increase of production taxes expressed on a dollars per Mcfe basis.
Depreciation, depletion, and amortization (“DD&A”) remained consistent, totaling $9,070 and $9,097 in the six months ended June 30, 2010 and 2009, respectively, and depletion and amortization related to producing assets totaled $8,866 and $8,879 in the six months ended June 30, 2010 and 2009, respectively. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 4%, or $0.07, to $1.97, as compared to the same prior-year period.
Pipeline operating costs
During the six months ended June 30, 2010, pipeline operating costs increased to $2,119 from $1,654. The Catalina Unit expanded from 47 producing wells to 67 producing wells throughout the first quarter of 2009. As a result of this expansion, our power and fuel costs increased. The 2010 pipeline operating costs reflect a full six months of the increased power and fuel charges. In addition, we incurred consulting costs related to refiguring our compressor units. The 2009 expenses were net of a vendor credit we received for compressor downtime, which lowered the pipeline operating costs for the period.
General and administrative expenses
General and administrative expenses decreased 6% to $2,925 for the six months ended June 30, 2010, as compared to $3,101 for the six months ended June 30, 2009. General and administrative expenses were higher during the six months ended June 30, 2009, primarily due to merger-related costs of $382 that resulted from the Petrosearch acquisition. In addition, stock-based compensation expense decreased by $274 in the 2010 period primarily to the timing of our 2009 executive bonus payout, which was paid at the end of 2009, instead of the first quarter of 2010, as had occurred in the prior year and stock forfeitures related to two executive terminations in the second quarter of 2010. These decreases were offset by a $125 increase in non-merger related legal costs, additional salary and salary-related expenses of approximately $119 primarily driven by non-executive salary increases and higher benefit costs, and higher audit and tax fees of approximately $65.
Income taxes
During the six months ended June 30, 2010, we recorded income tax expense of $2,945 compared to income tax expense of $521 during the same prior-year period. Our effective tax rate for the six months ended June 30, 2010 was 36.0% compared to 40.5% for the same period of 2009. The rate was lower in the 2010 period due to a reduction in permanent income tax differences related to stock option expense and higher projected net income. Although we expect to continue to generate losses for federal income tax reporting purposes, our operations have resulted in a deferred tax position required under generally accepted accounting principles. We expect to recognize deferred income tax expense on taxable income for the remainder of 2010 at an expected federal and state rate of approximately 35.0%.
CONTRACTED VOLUMES
Changes in the market price of oil and natural gas can significantly affect our profitability and cash flow. We have entered into various derivative instruments to mitigate the risk associated with downward fluctuations in the natural gas price. Historically these derivative instruments have consisted of fixed delivery contracts, swaps, options and costless collars. The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy.

 

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Our outstanding derivative instruments as of June 30, 2010 are summarized below (volume and daily production are expressed in Mcf):
                             
    Remaining                    
    Contractual     Daily             Price
Type of Contract   Volume     Production     Term   Price   Index (1)
                             
Fixed Price Swap
    2,208,000       12,000     1/10-12/10   $4.30   CIG
Fixed Price Swap
    2,920,000       8,000     1/11-12/11   $7.07   CIG
Costless Collar
    1,980,000       5,000     8/09-7/11   $4.50 floor   NYMEX
 
                      $7.90 ceiling    
Costless Collar
    2,590,000       5,000     12/09-11/11   $4.50 floor   NYMEX
 
                      $9.00 ceiling    
                         
Total
    9,698,000                      
                         
     
(1)  
NYMEX refers to quoted prices on the New York Mercantile Exchange. CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month.
Refer to Note 3 in the Notes to the Consolidated Financial Statements for additional discussion on the accounting treatment of our derivative contracts.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2009, and to the Notes to the Consolidated Financial Statements included in Part I, Item 1 of this report.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risks
Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for oil production and natural gas has been volatile and unpredictable for several years. The prices we receive for production depend on many factors outside of our control. For the three months ended June 30, 2010, our income before income taxes would have changed by $105 for each $0.50 change per Mcf in natural gas prices and $5 for each $1.00 change per Bbl in crude oil prices.
We have entered into natural gas derivative contracts to manage our exposure to natural gas price volatility. Our derivative instruments typically consist of forward sales contracts, swaps, and collars, which allow us to effectively “lock in” a portion of our future production of natural gas at prices that we consider favorable to Double Eagle at the time we enter into the contract. These derivative instruments which have differing expiration dates, are summarized in the table presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contracted Volumes.”
Interest Rate Risks
At June 30, 2010, we had a total of $31.0 million outstanding under our $75 million credit facility. We pay interest on outstanding borrowings under our credit facility at interest rates that fluctuate based upon changes in our levels of outstanding debt and the prevailing market rates. The minimum interest rate is 4.5%. As the interest rate is variable and reflective of current market conditions, the carrying value approximates the fair value. Assuming no change in the amount outstanding at June 30, 2010, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $310 before taxes. As of June 30, 2010, the interest rate on the line of credit, calculated in accordance with the agreement, was 4.5%.
In August 2010, we amended our credit facility to increase the borrowing availability on the line of credit from $45 million to $55 million. The increase in borrowing availability was supported by existing reserves and the addition of the additional reserves acquired through our asset purchase in the Atlantic Rim in July 2010. There were no modifications made to the interest rate calculation as part of the amendment. Any balance outstanding on the facility matures on January 31, 2013.

 

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ITEM 4. CONTROLS AND PROCEDURES
In accordance with the Securities Exchange Act of 1934, Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Accounting Officer), of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on this evaluation, our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Accounting Officer) have concluded that our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.
There has been no change in our internal control over financial reporting that occurred during the quarter ended June 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
From time to time, we are involved in various legal proceedings, including the matters discussed below. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters, and while the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.
The Company, along with other plaintiffs, filed a lawsuit on August 24, 2007, in the District Court of Fremont County, Wyoming, against Conoco/Phillips and other defendants who own working interests in the Madden Deep Unit. The Company and the other plaintiffs in the case are asserting that, under the gas balancing agreement, they are entitled to receive either monetary damages or their respective shares of the natural gas produced from the Madden Deep Unit over at least the period February 1, 2002 through June 30, 2007. For the period from November 1, 2006 through June 30, 2007, the Company has recognized the sales and has recorded a related account receivable of $292, net of allowance for uncollectible amounts. Subsequent to June 2007, the Company continued to recognize sales for its share of production and has consistently collected on the receivables due. As of June 30, 2010, the Company has not recognized any amount of sales proceeds for the period February 1, 2002 through October 30, 2006. Sulfur sales are not subject to a gas balancing agreement, and, accordingly, the Company received the proceeds for its share of sulfur sales dating back to February 2002 and has continued to receive its respective share on an on-going basis. Subsequent to the end of the second quarter, the Company signed a settlement agreement with many of the defendants in the lawsuit, in which the Company will receive cash proceeds of approximately $4.0 million. The Company expects to receive the settlement in the third quarter of 2010. The Company’s results for the second quarter 2010 do not include an accrual for this amount.
On December 18, 2009, Tiberius Capital, LLC (“Plaintiff”), a stockholder of Petrosearch Energy Corporation (“Petrosearch”) prior to the Company’s acquisition (the “Acquisition”) of Petrosearch pursuant to a merger between Petrosearch and a wholly-owned subsidiary of the Company, filed a claim in the US District Court of New York against Petrosearch, the Company, and the individuals who were officers and directors of Petrosearch prior to the Acquisition. In general, the claims against the Company and Petrosearch are that Petrosearch inappropriately denied dissenters’ rights of appraisal under the Nevada Revised Statutes to its stockholders in connection with the Acquisition, that the defendants violated various sections of the Securities Act of 1933 and the Securities Exchange Act of 1934, and that the defendants caused other damages to the stockholders of Petrosearch. The Plaintiff is seeking monetary damages. The Company does not believe the case has merit, and intends to defend this case vigorously.
ITEM 1A. RISK FACTORS
There have been no material changes in our Risk Factors from those reported in Item 1A of Part I of our 2009 Annual Report on Form 10-K filed with the Securities and Exchange Commission, which we incorporate by reference herein.

 

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ITEM 6. EXHIBITS
The following exhibits are filed as part of this report:
         
Exhibit   Description:
       
 
  3.1 (a)  
Articles of Incorporation filed with the Maryland Secretary of State on January 23, 2001 (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
       
 
  3.1 (b)  
Certificate of Correction filed with the Maryland Secretary of State on February 15, 2001 concerning the Articles of Incorporation (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
       
 
  3.1 (c)  
Articles of Merger filed with the Maryland Secretary of State on February 15, 2001 (incorporated by reference from Exhibit 3.1(c) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
       
 
  3.1 (d)  
Certificate of Correction filed with the Maryland Secretary of State (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001).
       
 
  3.1 (e)  
Certificate of Correction to the Articles of Incorporation, filed with the Maryland Department of Assessments and Taxation on June 1, 2007 (incorporated by reference from Exhibit 3.3 of the Company’s Current Report of Form 8-K dated June 29, 2007).
       
 
  3.1 (f)  
Articles of Amendment, filed with the Maryland Department of Assessments and Taxation on June 26, 2007 (incorporated by reference from Exhibit 3.1 of the company’s Current report on Form 8-K dated June 29, 2007).
       
 
  3.1 (g)  
Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report of Form 8-K dated June 29, 2007).
       
 
  3.1 (h)  
Articles Supplementary of Junior Participating Preferred Stock, Series B, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current report of Form 8-K dated August 28, 2007).
       
 
  3.1 (i)  
Amendment to Bylaws, New Article II, Section 3 — Quorum (incorporated by reference from Exhibit 3.1 of the company’s Current report on Form 8-K dated March 5, 2010).
       
 
  3.2 (a)  
Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Annual Report on Form 10-KSB, filed for the year ended August 31, 2001).
       
 
  3.2 (b)  
Bylaws of the Company, as amended and restated on March 14, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K, filed on March 14, 2007).
       
 
  3.2 (c)  
Second Amendment and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 11, 2007).
       
 
  4.1 (a)  
Form of Warrant Agreement concerning Common Stock Purchase Warrants (incorporated by reference from Exhibit 4.3 of the Amendment No. 1 to the Company’s Registration Statement on Form SB-2 filed on November 27, 1996, SEC Registration No. 333-14011).
       
 
  4.1 (b)  
Shareholder Rights Agreement, dated as of August 24, 2007 (incorporated herein by reference to the Company’s Current report on Form 8-A filed on August 24, 2007).
       
 
  4.1 (c)  
Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 29, 2007).
       
 
  4.1 (d)  
Articles Supplementary of Junior Participating Preferred Stock, Series B, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current report of Form 8-K dated August 28, 2007).
       
 
  31.1    
Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Rule 13a — 14(a) and Rule 15a —14(a) of the Securities Exchange Act, as amended.
       
 
  31.2    
Certification of Chief Financial Officer (Principal Accounting Officer) pursuant to Rule 13a — 14(a) and Rule 15a — 14(a) of the Securities Exchange Act, as amended.
       
 
  32    
Certification of Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Accounting Officer) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002.

 

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
         
  DOUBLE EAGLE PETROLEUM CO.
(Registrant)
 
 
Date: August 5, 2010  By:   /s/ Richard D. Dole    
    Richard D. Dole   
    Chief Executive Officer
(Principal Executive Officer) 
 
 
     
Date: August 5, 2010  By:   /s/ Kurtis S. Hooley    
    Kurtis S. Hooley   
    Chief Financial Officer
(Principal Accounting Officer) 
 

 

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EXHIBIT INDEX
         
Exhibit Number   Description
       
 
  3.1 (a)  
Articles of Incorporation filed with the Maryland Secretary of State on January 23, 2001 (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
       
 
  3.1 (b)  
Certificate of Correction filed with the Maryland Secretary of State on February 15, 2001 concerning the Articles of Incorporation (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
       
 
  3.1 (c)  
Articles of Merger filed with the Maryland Secretary of State on February 15, 2001 (incorporated by reference from Exhibit 3.1(c) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
       
 
  3.1 (d)  
Certificate of Correction filed with the Maryland Secretary of State (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001).
       
 
  3.1 (e)  
Certificate of Correction to the Articles of Incorporation, filed with the Maryland Department of Assessments and Taxation on June 1, 2007 (incorporated by reference from Exhibit 3.3 of the Company’s Current Report of Form 8-K dated June 29, 2007).
       
 
  3.1 (f)  
Articles of Amendment, filed with the Maryland Department of Assessments and Taxation on June 26, 2007 (incorporated by reference from Exhibit 3.1 of the company’s Current report on Form 8-K dated June 29, 2007).
       
 
  3.1 (g)  
Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report of Form 8-K dated June 29, 2007).
       
 
  3.1 (h)  
Articles Supplementary of Junior Participating Preferred Stock, Series B, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current report of Form 8-K dated August 28, 2007).
       
 
  3.1 (i)  
Amendment to Bylaws, New Article II, Section 3 — Quorum (incorporated by reference from Exhibit 3.1 of the company’s Current report on Form 8-K dated March 5, 2010).
       
 
  3.2 (a)  
Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Annual Report on Form 10-KSB, filed for the year ended August 31, 2001).
       
 
  3.2 (b)  
Bylaws of the Company, as amended and restated on March 14, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K, filed on March 14, 2007).
       
 
  3.2 (c)  
Second Amendment and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 11, 2007).
       
 
  4.1 (a)  
Form of Warrant Agreement concerning Common Stock Purchase Warrants (incorporated by reference from Exhibit 4.3 of the Amendment No. 1 to the Company’s Registration Statement on Form SB-2 filed on November 27, 1996, SEC Registration No. 333-14011).

 

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Exhibit Number   Description
       
 
  4.1 (b)  
Shareholder Rights Agreement, dated as of August 24, 2007 (incorporated herein by reference to the Company’s Current report on Form 8-A filed on August 24, 2007)
       
 
  4.1 (c)  
Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 29, 2007).
       
 
  4.1 (d)  
Articles Supplementary of Junior Participating Preferred Stock, Series B, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current report of Form 8-K dated August 28, 2007).
       
 
  31.1    
Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Rule 13a — 14(a) and Rule 15a — 14(a) of the Securities Exchange Act, as amended.
       
 
  31.2    
Certification of Chief Financial Officer (Principal Accounting Officer) pursuant to Rule 13a — 14(a) and Rule 15a — 14(a) of the Securities Exchange Act, as amended.
       
 
  32    
Certification of Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Accounting Officer) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002.

 

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