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Venoco 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

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TABLE OF CONTENTS

Table of Contents

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



Form 10-Q


ý

 

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

Commission File Number: 333-123711

Venoco, Inc.

Delaware
(State or other jurisdiction of
incorporation or organization)
  77-0323555
(I.R.S. Employer
Identification Number)

370 17th Street, Suite 3900
Denver, Colorado

(Address of principal executive offices)

 

80202-1370
(Zip Code)

Registrant's telephone number, including area code: (303) 626-8300

N/A
(Former name or former address, and former fiscal year, if changed since last report)

        Indicate by check mark whether the registrant (1) has filed all reports required 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 ý    NO o

        Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES o    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 ý   Non-accelerated filer o
(Do not check if a
smaller reporting company)
  Smaller reporting company o

        Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES o    NO ý

        As of June 30, 2010, there were 54,811,238 shares of the issuer's common stock, par value $0.01 per share, issued and outstanding.


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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

        This report on Form 10-Q contains "forward-looking statements" as that term is defined in the Private Securities Litigation Reform Act of 1995. The use of any statements containing the words "anticipate," "intend," "believe," "estimate," "project," "expect," "plan," "should" or similar expressions are intended to identify such statements. Forward-looking statements included in this report relate to, among other things, expected future production, expenses and cash flows, the nature, timing and results of capital expenditure projects, amounts of future capital expenditures, our future debt levels and liquidity, our future compliance with covenants under our revolving credit facility, our pursuit and receipt of approvals relating to the proposed lease extension and pipeline projects at the South Ellwood field and the maintenance of delivery and sales arrangements relating to production from the South Ellwood field. The expectations reflected in such forward-looking statements may prove to be incorrect. Disclosure of important factors that could cause actual results to differ materially from our expectations, or cautionary statements, are included under the heading "Risk Factors" in this report and our Annual Report on Form 10-K for the year ended December 31, 2009. Certain cautionary statements are also included elsewhere in this report, including, without limitation, in conjunction with the forward-looking statements. All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements. Except as required by law, we undertake no obligation to update any forward-looking statement. Factors that could cause actual results to differ materially from our expectations include, among others, those factors referenced in the "Risk Factors" section of this report and our Annual Report on Form 10-K for the year ended December 31, 2009 and such things as:

    changes in oil and natural gas prices, including reductions in prices that would adversely affect our revenues, income, cash flow from operations, liquidity and reserves;

    adverse conditions in global credit markets and in economic conditions generally;

    risks related to our level of indebtedness;

    our ability to replace oil and natural gas reserves;

    risks arising out of our hedging transactions;

    our inability to access oil and natural gas markets due to operational impediments;

    uninsured or underinsured losses in, or operational problems affecting, our oil and natural gas operations;

    inaccuracy in reserve estimates and expected production rates;

    exploitation, development and exploration results, including in the Monterey shale, where our results will depend on, among other things, our ability to identify productive intervals and drilling and completion techniques necessary to achieve commercial production from those intervals;

    our ability to manage expenses, including expenses associated with asset retirement obligations;

    a lack of available capital and financing, including as a result of a reduction in the borrowing base under our revolving credit facility;

    the existence of unanticipated liabilities or problems relating to acquired businesses or properties;

    difficulties involved in the integration of operations we have acquired or may acquire in the future;

    factors affecting the nature and timing of our capital expenditures;

    the impact and costs related to compliance with or changes in laws or regulations governing or affecting our operations, including changes resulting from the Deepwater Horizon well blowout

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      in the Gulf of Mexico and from the Dodd-Frank Wall Street Reform and Consumer Protection Act or its implementing regulations;

    delays, denials or other problems relating to our receipt of operational consents and approvals from governmental entities and other parties;

    environmental liabilities;

    loss of senior management or technical personnel;

    acquisitions and other business opportunities (or the lack thereof) that may be presented to and pursued by us;

    risk factors discussed in this report; and

    other factors, many of which are beyond our control.

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VENOCO, INC.
Form 10-Q for the Quarterly Period Ended June 30, 2010

TABLE OF CONTENTS

PART I.

 

FINANCIAL INFORMATION

       

Item 1.

 

Financial Statements (Unaudited)

       

 

Condensed Consolidated Balance Sheets at December 31, 2009 and June 30, 2010

    2  

 

Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2009 and the Three and Six Months Ended June 30, 2010

    3  

 

Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2009 and the Three and Six Months Ended June 30, 2010

    4  

 

Condensed Consolidated Statements of Changes in Stockholders' Equity for the Six Months Ended June 30, 2010

    5  

 

Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and the Six Months Ended June 30, 2010

    6  

 

Notes to Condensed Consolidated Financial Statements

    7  

Item 2.

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

    31  

Item 3.

 

Quantitative and Qualitative Disclosures about Market Risk

    45  

Item 4.

 

Controls and Procedures

    49  

PART II.

 

OTHER INFORMATION

       

Item 1.

 

Legal Proceedings

    50  

Item 1A.

 

Risk Factors

    50  

Item 2.

 

Unregistered Sales of Equity Securities and Use of Proceeds

    50  

Item 3.

 

Defaults upon Senior Securities

    50  

Item 4.

 

Removed and Reserved

    50  

Item 5.

 

Other Information

    51  

Item 6.

 

Exhibits

    51  

Signatures

    52  

1


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PART I—FINANCIAL INFORMATION

VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(In thousands, except shares and per share amounts)

 
  December 31,
2009
  June 30,
2010
 

ASSETS

             

CURRENT ASSETS:

             
 

Cash and cash equivalents

  $ 419   $ 2,204  
 

Accounts receivable, net of allowance for doubtful accounts of $900 and $700 at December 31, 2009 and June 30, 2010, respectively

    33,853     26,927  
 

Inventories

    6,139     6,231  
 

Prepaid expenses and other current assets

    4,276     3,289  
 

Income taxes receivable

    3,116     11,966  
 

Deferred income taxes

    8,400      
 

Commodity derivatives

    34,611     39,613  
           
   

Total current assets

    90,814     90,230  
           

PROPERTY, PLANT AND EQUIPMENT, AT COST:

             
 

Oil and natural gas properties (full cost method, of which $31,934 and $41,902 for unproved properties were excluded from amortization at December 31, 2009 and June 30, 2010, respectively)

    1,672,901     1,668,121  
 

Drilling equipment

    14,460     14,460  
 

Other property and equipment

    20,608     20,270  
           
 

Total property, plant and equipment

    1,707,969     1,702,851  
 

Accumulated depletion, depreciation and amortization

    (1,088,539 )   (1,125,517 )
           
     

Net property, plant and equipment

    619,430     577,334  
           

OTHER ASSETS:

             
 

Commodity derivatives

    18,720     32,057  
 

Deferred loan costs

    7,908     6,846  
 

Other

    2,671     2,622  
           
   

Total other assets

    29,299     41,525  
           

TOTAL ASSETS

  $ 739,543   $ 709,089  
           

LIABILITIES AND STOCKHOLDERS' EQUITY

             

CURRENT LIABILITIES:

             
 

Accounts payable and accrued liabilities

  $ 48,709   $ 41,040  
 

Undistributed revenue payable

    8,146     5,274  
 

Interest payable

    4,885     5,367  
 

Commodity and interest derivatives

    49,709     24,478  
           
   

Total current liabilities

    111,449     76,159  

LONG-TERM DEBT

    695,029     632,749  

COMMODITY AND INTEREST DERIVATIVES

    15,076     27,368  

ASSET RETIREMENT OBLIGATIONS

    92,485     91,374  
           
   

Total liabilities

    914,039     827,650  

COMMITMENTS AND CONTINGENCIES

             

STOCKHOLDERS' EQUITY:

             
 

Common stock, $.01 par value (200,000,000 shares authorized; 52,513,397 and 54,811,238 shares issued and outstanding at December 31, 2009 and June 30, 2010, respectively)

    525     548  
 

Additional paid-in capital

    325,871     334,086  
 

Retained earnings (accumulated deficit)

    (500,892 )   (453,195 )
           
   

Total stockholders' equity

    (174,496 )   (118,561 )
           

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

  $ 739,543   $ 709,089  
           

See notes to condensed consolidated financial statements.

2


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VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(In thousands, except per share amounts)

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2009   2010   2009   2010  

REVENUES:

                         
 

Oil and natural gas sales

  $ 62,011   $ 68,876   $ 119,442   $ 151,377  
 

Other

    803     1,566     1,688     2,386  
                   
   

Total revenues

    62,814     70,442     121,130     153,763  

EXPENSES:

                         
 

Oil and natural gas production

    25,539     23,945     52,265     47,017  
 

Transportation expense

    764     3,045     1,810     4,688  
 

Depletion, depreciation and amortization

    20,608     18,742     43,291     38,716  
 

Accretion of asset retirement obligations

    1,388     1,546     2,745     3,131  
 

General and administrative, net of amounts capitalized

    8,559     10,762     16,557     20,171  
                   
   

Total expenses

    56,858     58,040     116,668     113,723  
                   
   

Income (loss) from operations

    5,956     12,402     4,462     40,040  

FINANCING COSTS AND OTHER:

                         
 

Interest expense, net

    9,777     10,298     20,955     20,422  
 

Amortization of deferred loan costs

    738     679     1,473     1,356  
 

Interest rate derivative losses (gains), net

    7,953     16,276     8,900     25,800  
 

Loss on extinguishment of debt

    582         582      
 

Commodity derivative losses (gains), net

    50,483     (18,560 )   1,924     (55,035 )
                   
   

Total financing costs and other

    69,533     8,693     33,834     (7,457 )
                   
   

Income (loss) before income taxes

    (63,577 )   3,709     (29,372 )   47,497  

Income tax provision (benefit)

    (4,100 )       4,900     (200 )
                   
   

Net income (loss)

  $ (59,477 ) $ 3,709   $ (34,272 ) $ 47,697  
                   

Earnings per common share:

                         
 

Basic

  $ (1.17 ) $ 0.07   $ (0.68 ) $ 0.88  
 

Diluted

  $ (1.17 ) $ 0.07   $ (0.68 ) $ 0.86  

Weighted average common shares outstanding:

                         
 

Basic

    50,781     51,826     50,742     51,557  
 

Diluted

    50,781     53,043     50,742     52,629  

See notes to condensed consolidated financial statements.

3


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VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

(In thousands)

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2009   2010   2009   2010  

Net income (loss)

  $ (59,477 ) $ 3,709   $ (34,272 ) $ 47,697  

OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:

                         

Hedging activities:

                         
 

Reclassification adjustments for settled contracts

    580         1,202      
                   

Other comprehensive income (loss)

    580         1,202      
                   

Comprehensive income (loss)

  $ (58,897 ) $ 3,709   $ (33,070 ) $ 47,697  
                   

See notes to condensed consolidated financial statements.

4


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VENOCO, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

(UNAUDITED)

(In thousands)

 
  Common Stock    
  Retained
Earnings
(Accumulated
Deficit)
   
 
 
  Additional
Paid-in
Capital
   
 
 
  Shares   Amount   Total  

BALANCE AT DECEMBER 31, 2009

    52,513   $ 525   $ 325,871   $ (500,892 ) $ (174,496 )
 

Issuance of stock for cash upon exercise of options

    594     6     4,096         4,102  
 

Issuance of restricted shares, net of cancellations

    1,688     17     (17 )        
 

Share-based compensation

            3,940         3,940  
 

Issuance of common stock pursuant to Employee Stock Purchase Plan

    16         196         196  
 

Net income (loss)

                47,697     47,697  
                       

BALANCE AT JUNE 30, 2010

    54,811   $ 548   $ 334,086   $ (453,195 ) $ (118,561 )
                       

See notes to condensed consolidated financial statements.

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VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In thousands)

 
  Six Months Ended
June 30,
 
 
  2009   2010  

CASH FLOWS FROM OPERATING ACTIVITIES:

             
 

Net income (loss)

  $ (34,272 ) $ 47,697  
 

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

             
   

Depletion, depreciation and amortization

    43,291     38,716  
   

Accretion of asset retirement obligations

    2,745     3,131  
   

Deferred income tax provision (benefit)

        8,400  
   

Share-based compensation

    1,194     2,731  
   

Amortization of deferred loan costs

    1,473     1,356  
   

Amortization of bond discounts and other non-cash interest

    304     290  
   

Loss on extinguishment of debt

    582      
   

Unrealized interest rate swap derivative losses (gains)

    (170 )   16,732  
   

Unrealized commodity derivative losses (gains) and amortization of premiums and other comprehensive loss

    50,200     (42,029 )
 

Changes in operating assets and liabilities:

             
   

Accounts receivable

    10,029     6,926  
   

Inventories

    (512 )   (421 )
   

Prepaid expenses and other current assets

    1,512     918  
   

Income taxes receivable

    4,340     (8,850 )
   

Other assets

    (381 )   49  
   

Accounts payable and accrued liabilities

    (21,430 )   (11,685 )
   

Undistributed revenue payable

    (3,633 )   (2,872 )
 

Net premiums paid on derivative contracts

    (8,012 )   (5,981 )
           
     

Net cash provided by operating activities

    47,260     55,108  

CASH FLOWS FROM INVESTING ACTIVITIES:

             
 

Expenditures for oil and natural gas properties

    (116,671 )   (90,729 )
 

Acquisitions of oil and natural gas properties

    (21,575 )   (2,232 )
 

Expenditures for other property and equipment

    (1,128 )   (1,310 )
 

Proceeds from sale of oil and natural gas properties

    200,060     99,445  
           
   

Net cash (used in) provided by investing activities

    60,686     5,174  

CASH FLOWS FROM FINANCING ACTIVITIES:

             
 

Proceeds from long-term debt

    102,394     75,000  
 

Principal payments on long-term debt

    (209,016 )   (137,570 )
 

Payments for deferred loan costs

    (275 )   (225 )
 

Proceeds from Employee Stock Purchase Plan

    155     196  
 

Proceeds from disgorgement of stock sale profits

    15      
 

Proceeds from exercise of stock options

    174     4,102  
           
   

Net cash (used in) provided by financing activities

    (106,553 )   (58,497 )
           
     

Net increase (decrease) in cash and cash equivalents

    1,393     1,785  
 

Cash and cash equivalents, beginning of period

    191     419  
           
     

Cash and cash equivalents, end of period

  $ 1,584   $ 2,204  
           

Supplemental Disclosure of Cash Flow Information—

             
 

Cash paid for interest

  $ 24,301   $ 19,705  
 

Cash paid for income taxes

  $ 560   $ 250  

Supplemental Disclosure of Noncash Activities—

             
 

Accrued capital expenditures at period end

  $ 15,028   $ 19,232  
 

Increase (decrease) in accrued capital expenditures

  $ (15,175 ) $ 3,998  

See notes to condensed consolidated financial statements.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES

        Description of Operations—Venoco, Inc. ("Venoco" or the "Company"), a Delaware corporation, is engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties with a focus on properties offshore and onshore in California.

        Basis of Presentation—The unaudited condensed consolidated financial statements include the accounts of Venoco and its subsidiaries, all of which are wholly owned. The financial statements have been prepared in accordance with U.S. generally accepted accounting principles for interim financial reporting. All significant intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, all material adjustments considered necessary for a fair presentation of the Company's interim results have been reflected. The Company has evaluated subsequent events and transactions for matters that may require recognition or disclosure in these financial statements. Venoco's Annual Report on Form 10-K for the year ended December 31, 2009 includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this report. The results for interim periods are not necessarily indicative of annual results.

        In the course of preparing the condensed consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash flow estimates used in ceiling tests of oil and natural gas properties; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of commodity and interest rate derivative instruments; (8) accrued liabilities; (9) valuation of share-based payments and (10) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates.

        Income Taxes—The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to its year-to-date income or loss, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. The Company incurred losses before income taxes in 2008 and 2009. These losses were a key consideration that led the Company to provide a valuation allowance against its net deferred tax assets at December 31, 2009 and June 30, 2010 since it could not conclude that it is more likely than not that the net deferred tax assets will be fully realized on future tax returns. As long as the Company concludes that it will continue to have a need for a full valuation allowance against its net deferred tax assets, the Company likely will not have any income tax expense or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims or for state income taxes. The income tax expense for the six months ended June 30, 2009 primarily relates to federal AMT resulting from the sale of the Hastings Complex in February 2009 and state income taxes. The income tax benefit for the six months ended June 30, 2010, relates to an increase in the estimated net operating loss carryback claim for the 2003 through 2005 tax years.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

        Earnings Per Share—Basic earnings (loss) per share is calculated by dividing net earnings (loss) attributable to common stock by the weighted average number of shares outstanding for the period (unvested restricted stock is excluded from the weighted average shares outstanding used in the basic earnings per share calculation). Under the treasury stock method, diluted earnings per share is calculated by dividing net earnings (loss) by the weighted average number of shares outstanding including all potentially dilutive common shares (unvested restricted stock and unexercised stock options). In the event of a net loss, no potential common shares are included in the calculation of shares outstanding, as their inclusion would be anti-dilutive.

        Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The Company's unvested restricted stock awards contain nonforfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted stock does not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Consequently, in periods of net loss, the two class method will not have an effect on the Company's basic earnings per share.

        The following table details the weighted average dilutive and anti-dilutive securities for the periods presented (in thousands):

 
  Three Months
Ended
June 30,
  Six Months
Ended
June 30,
 
 
  2009   2010   2009   2010  

Dilutive

        5,231         4,982  

Anti-dilutive

    5,106     511     4,862     591  

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

        The following table sets forth the calculation of basic and diluted earnings per share (in thousands except per share amounts):

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2009   2010   2009   2010  

Net income (loss)

  $ (59,477 ) $ 3,709   $ (34,272 ) $ 47,697  

Allocation of net income to unvested restricted stock

        (190 )       (2,225 )
                   
 

Net income (loss) allocated to common stock

  $ (59,477 ) $ 3,519   $ (34,272 ) $ 45,472  
                   

Basic weighted average common shares outstanding

    50,781     51,826     50,742     51,557  
 

Add: dilutive effect of stock options

        1,217         1,072  
                   

Diluted weighted average common shares outstanding

    50,781     53,043     50,742     52,629  
                   

Basic earnings per common share

  $ (1.17 ) $ 0.07   $ (0.68 ) $ 0.88  

Diluted earnings per common share

  $ (1.17 ) $ 0.07   $ (0.68 ) $ 0.86  

        In January 2010, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2010-06, Improving Disclosures about Fair Value Measurements ("ASU 2010-06"), which amends existing authoritative guidance to provide for additional disclosures regarding (i) transfer in and out of Levels 1 and 2, (ii) activity in Level 3 fair value measurements, (iii) the classes of assets and liabilities measured at fair value, and (iv) the inputs and valuation techniques used to measure fair value. ASU 2010-06 is effective for fiscal years and interim periods beginning after December 15, 2009. The adoption of ASU 2010-06, effective January 1, 2010, has not had an impact on the Company's consolidated financial statements, other than additional disclosures.

2. ACQUISITIONS AND SALES OF PROPERTIES

        Sales of Texas Assets.    In April 2010, the Company signed certain Purchase and Sale Agreements ("PSAs") to divest its producing properties in Texas ("Texas Sales") for $107.5 million (before closing adjustments), each with an effective date of January 1, 2010. The PSAs covered the Company's interests in the Manvel field, the Company's overriding royalty interest in the Hastings Complex and its other oil and natural gas producing properties in the Texas Gulf Coast. The sales closed in a series of transactions in the second quarter of 2010 and involved multiple purchasers, including Denbury Resources, Inc., ("Denbury") which purchased the overriding royalty interest in the Hastings Complex. The aggregate net proceeds from the transactions were $99.4 million (after closing adjustments and related expenses). The Company used the proceeds from the sales to repay $66.9 million of the principal balance on the revolving credit facility and $30.7 million of the principal balance on the second lien term loan. The Company did not recognize a gain or loss for financial reporting purposes on the sale in accordance with the full cost method of accounting, but applied the proceeds from the Texas Sales to reduce the capitalized cost of its oil and natural gas properties. As a result of the Texas Sales, the Company no longer has any interests in producing oil and natural gas properties in Texas. The Company did however, retain its 22.3% reversionary working interest in the Hastings Complex.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

2. ACQUISITIONS AND SALES OF PROPERTIES (Continued)

        Sacramento Basin Asset Acquisition.    In February 2009, the Company entered into a purchase and sale agreement to acquire certain natural gas producing properties in the Sacramento Basin. The transaction closed in June 2009 with a total purchase price of $21.4 million. The acquisition qualified as a business combination and was therefore recorded at the estimated fair value of the assets acquired and liabilities assumed.

        Hastings Complex Sale.    In February 2009, the Company completed the sale of its principal interests in the Hastings Complex to Denbury for approximately $197.7 million. As a result of the sale, the Company repaid all amounts then outstanding under the revolving credit facility and $5.5 million of the outstanding principal balance on the second lien term loan facility. The proceeds from the Hastings Complex sale were applied as a reduction of capitalized costs of oil and natural gas properties.

        As a result of the sale, Denbury committed to a development plan related to a CO2 enhanced recovery project that will require it to make minimum capital expenditures in the amount of $178.7 million by the end of 2014. As part of the plan, Denbury is responsible for providing the necessary CO2. The Company retained an overriding royalty interest of 2.0% in the production from the properties, which was subsequently sold to Denbury in the second quarter of 2010, as described above. In addition, the Company has the right to back-in to a working interest of approximately 22.3% in the CO2 project after Denbury recoups certain costs.

3. LONG-TERM DEBT

        As of the dates indicated, the Company's long-term debt consisted of the following (in thousands):

 
  December 31,
2009
  June 30,
2010
 

Revolving credit agreement due January 2013

  $ 57,860   $ 26,000  

Second lien term loan due May 2014

    494,485     463,776  

11.50% senior notes due October 2017

    142,684     142,973  
           
 

Total long-term debt

    695,029     632,749  

Less: current portion of long-term debt

         
           
 

Long-term debt, net of current portion

  $ 695,029   $ 632,749  
           

        Revolving credit facility.    In December 2009, the Company entered into the Third Amended and Restated Credit Agreement related to its $300 million revolving credit facility with a syndicate of banks ("revolving credit facility"). The facility has a maturity date of January 15, 2013 and the borrowing base (currently established at $125 million) is subject to redetermination twice each year, and may be redetermined at other times at the Company's request or at the request of the lenders. The facility is secured by a first priority lien on substantially all of the Company's oil and natural gas properties and other assets, including the equity interests in all of the Company's subsidiaries, and is unconditionally guaranteed by each of the Company's operating subsidiaries other than Ellwood Pipeline, Inc. The collateral also secures the Company's obligations to hedging counterparties that are also lenders, or affiliates of lenders, under the facility. Loans designated as Base Rate Loans under the facility bear interest at a floating rate equal to (i) the greater of (x) the Bank of Montreal's announced base rate,

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(UNAUDITED)

3. LONG-TERM DEBT (Continued)


(y) the overnight federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.5%, plus (ii) an applicable margin ranging from 0.75% to 1.50%, based upon utilization. Loans designated as LIBO Rate Loans under the facility bear interest at (i) LIBOR plus (ii) an applicable margin ranging from 2.25% to 3.00%, based upon utilization. A commitment fee of 0.50% per annum is payable with respect to unused borrowing availability under the facility. The agreement governing the facility contains customary representations, warranties, events of default, indemnities and covenants, including operational covenants that restrict the Company's ability to incur indebtedness and financial covenants that require the Company to maintain specified ratios of current assets to current liabilities and debt to EBITDA.

        The borrowing base under the revolving credit facility has been allocated at various percentages to a syndicate of ten banks. Certain of the institutions included in the syndicate have received support from governmental agencies in connection with events in the credit markets. As of July 30, 2010, the Company had available borrowing capacity of $89.9 million under the facility, net of the outstanding balance of $31.0 million and $4.1 million in outstanding letters of credit. The lenders associated with the revolving credit facility performed the semi-annual borrowing base redetermination in May 2010 and have reaffirmed the borrowing base at $125 million.

        Second lien term loan facility.    The Company entered into its $500.0 million senior secured second lien term loan facility in May 2007 (the "second lien term loan facility"). Loans made under the second lien term loan facility are designated, at the Company's option, as either "Base Rate Loans" or "LIBO Rate Loans." Loans designated as Base Rate Loans bear interest at a floating rate equal to (i) the greater of the overnight federal funds rate plus 0.50% and a market base rate, plus (ii) 3.00%. Loans designated as LIBO Rate Loans bear interest at LIBOR plus 4.00%.

        The agreement governing the second lien term loan facility contains customary representations, warranties, events of default and indemnities and certain customary covenants, including covenants that restrict the Company's ability to incur additional indebtedness. The facility is secured by second priority liens on substantially all of the Company's oil and natural gas properties and other assets, including the equity interests in all of its subsidiaries, and is unconditionally guaranteed by each of the Company's subsidiaries other than Ellwood Pipeline, Inc. The maturity date of the principal on the second lien term loan facility is May 8, 2014.

        The Company may from time to time make optional prepayments of amounts borrowed under the second lien term loan facility (at par) if no amounts are outstanding under the revolving credit facility. Amounts prepaid under the second lien term loan facility may not be reborrowed. As a result of the Hastings Complex sale in February 2009, the Company was required to repay $5.5 million of the outstanding principal balance on the second lien term loan facility. Additionally, the Company was required to repay $30.7 million of the outstanding principal balance from the proceeds of the Texas Sales in the second quarter of 2010.

        Senior notes.    In October 2009, the Company issued $150.0 million of 11.50% senior notes due October 2017 at a price of 95.03% of par. The notes are senior unsecured obligations and contain covenants that, among other things, limit the Company's ability to make investments, incur additional debt, issue preferred stock, pay dividends, repurchase its stock, create liens or sell assets. The senior notes pay interest semi-annually in arrears on April 1 and October 1 of each year. The Company may

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(UNAUDITED)

3. LONG-TERM DEBT (Continued)


redeem the senior notes prior to October 1, 2013 at a "make-whole price" defined in the indenture. Beginning October 1, 2013, the Company may redeem the notes at a redemption price equal to 105.75% of the principal amount and declining to 100% by October 1, 2016.

        The Company was in compliance with all debt covenants at June 30, 2010.

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS

        Commodity Derivative Agreements.    The Company utilizes swap and collar agreements and option contracts to hedge the effect of price changes on a portion of its future oil and natural gas production. The objective of the Company's hedging activities and the use of derivative financial instruments is to achieve more predictable cash flows. While the use of these derivative instruments limits the downside risk of adverse price movements, they also may limit future revenues from favorable price movements. The Company may, from time to time, opportunistically restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts or realize the current value of the Company's existing positions and use the proceeds from such transactions to secure additional contracts for periods in which the Company believes it has additional unmitigated commodity price risk.

        The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company's derivative contracts are with multiple counterparties to minimize exposure to any individual counterparty. The Company generally has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with that counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. All of the counterparties to the Company's derivative contracts are also lenders, or affiliates of lenders, under its revolving credit facility. Collateral under the revolving credit facility supports the Company's collateral obligations under the Company's derivative contracts. Therefore, the Company is not required to post additional collateral when the Company is in a derivative liability position. The Company's revolving credit facility and derivative contracts contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations.

        Lehman Brothers Commodity Services, Inc. ("LBCS") was a counterparty to several derivative contracts with the Company entered into between August 2006 and May 2008. In September 2008, Lehman Brothers Holdings Inc. ("LBH"), credit support provider for LBCS, filed for bankruptcy. The bankruptcy filing of LBH constituted an event of default under the ISDA Master Agreement between the Company and LBCS. Accordingly, the Company notified LBCS that the Company was terminating each of the outstanding transactions, effective immediately. Subsequent to the Company's notification of termination, LBCS filed for bankruptcy protection. Similar issues could affect other hedge counterparties in the future.

        The Company has elected not to apply hedge accounting to any of its derivative transactions and, consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income for those commodity derivatives that would qualify as cash flow hedges.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

        The Company has paid premiums related to certain of its outstanding derivative contracts. These premiums are amortized over the period for which the contracts are effective. At June 30, 2010, the balance of unamortized derivative premiums was $33.2 million, of which $11.3 million, $15.3 million and $6.6 million will be amortized in the remainder of 2010, 2011 and 2012, respectively.

        The components of commodity derivative losses (gains) in the consolidated statements of operations are as follows (in thousands):

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2009   2010   2009   2010  

Realized commodity derivative (gains) losses

  $ (16,288 ) $ (10,345 ) $ (47,073 ) $ (13,006 )

Amortization of commodity derivative premiums

    6,048     5,658     10,663     11,315  

Unrealized commodity derivative (gains) losses for changes in fair value:

    60,723     (13,873 )   38,334     (53,344 )
                   
 

Commodity derivative (gains) losses

  $ 50,483   $ (18,560 ) $ 1,924   $ (55,035 )
                   

        As of June 30, 2010, the Company had entered into swap, collar and option agreements related to its oil and natural gas production. The aggregate economic effects of those agreements are summarized below. Location and quality differentials attributable to the Company's properties are not included in the following prices. The agreements provide for monthly settlement based on the differential between the agreement price and the actual NYMEX WTI (oil) or NYMEX Henry Hub (natural gas) price.

 
  Oil (NYMEX WTI)   Natural Gas
(NYMEX Henry Hub)
 
 
  Barrels/day   Weighted Avg.
Prices per Bbl
  MMBtu/day   Weighted Avg.
Prices per MMBtu
 

July 1 - December 31, 2010:

                         
 

Swaps

    1,000   $ 66.75       $  
 

Swap arrangements(1)

      $     11,000   $ 7.00  
 

Collars(1)

    5,150   $ 60.00/$86.53     6,900   $ 7.50/$7.00  
 

Collar arrangements(1)(2)

      $     10,000   $ 6.00/$7.00  
 

Puts

    1,850   $ 40.00     31,000   $ 6.00  

January 1 - December 31, 2011:

                         
 

Collars(1)

    5,000   $ 50.00/$140.40     12,000   $ 5.75/$7.12  
 

Puts(1)

    2,000   $ 50.00     48,000   $ 6.31  

January 1 - December 31, 2012:

                         
 

Collars(1)

    3,000   $ 60.00/$121.10       $  
 

Puts(1)

      $     37,300   $ 5.81  

(1)
Reflects the impact of call spreads and purchased calls, which are transactions entered into for the purpose of modifying or eliminating the ceiling (or call) portion of certain collar arrangements.

(2)
Reflects separate put and sold call contracts, resulting in a collar arrangement.

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(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

        The Company also uses natural gas basis swaps to fix the differential between the NYMEX Henry Hub price and the PG&E Citygate price, the index on which the majority of its natural gas is sold. The Company's natural gas basis swaps as of June 30, 2010 are presented below:

 
  Floating Index   MMBtu/Day   Weighted
Avg. Basis
Differential to
NYMEX HH
(per MMBtu)
 

Basis Swaps:

                 
 

July 1 - December 31, 2010

  PG&E Citygate     51,618   $ 0.14  
 

January 1 - December 31, 2011

  PG&E Citygate     57,224   $ 0.11  
 

January 1 - December 31, 2012

  PG&E Citygate     47,400   $ 0.28  

        Interest Rate Swap.    The Company has entered into interest rate swap transactions to lock in its interest cost on $500.0 million of variable rate borrowings through May 2014. The Company pays a fixed interest rate of 3.840% and receives a floating interest rate based on the three-month LIBO rate, with settlements made quarterly. As a result of the interest rate swap agreement, $500 million of the Company's variable rate debt will effectively bear interest at a fixed rate of approximately 7.8%. The Company did not designate the interest rate swap as a hedge.

        The components of interest rate derivative (gains) losses in the consolidated statements of operations are as follows (in thousands):

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2009   2010   2009   2010  

Realized interest rate derivative (gains) losses

  $ 5,130   $ 4,559   $ 9,070   $ 9,068  

Unrealized interest rate derivative (gains) losses

    2,823     11,717     (170 )   16,732  
                   
 

Interest rate derivative (gains) losses, net

  $ 7,953   $ 16,276   $ 8,900   $ 25,800  
                   

        Fair Value of Derivative Instruments.    The estimated fair values of derivatives included in the consolidated balance sheets at December 31, 2009 and June 30, 2010 are summarized below. The net fair value of the Company's derivatives increased by $31.3 million from a net liability of $11.5 million at December 31, 2009 to a net asset of $19.8 million at June 30, 2010, primarily due to changes in futures prices for oil and natural gas, which are used in the calculation of the fair value of commodity derivatives. The Company does not offset asset and liability positions with the same counterparties within the financial statements, rather, all contracts are presented at their gross estimated fair value. As of the dates indicated, the Company's derivative assets and liabilities are presented below (in thousands). These balances represent the estimated fair value of the contracts. The Company has not

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(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)


designated any of its derivative contracts as hedging instruments. The main headings represent the balance sheet captions for the contracts presented.

 
  December 31,
2009
  June 30,
2010
 

Current Assets—Commodity derivatives:

             
 

Oil derivative contracts

  $ 12,461   $ 6,084  
 

Gas derivative contracts

    22,150     33,529  
           

    34,611     39,613  
           

Other Assets—Commodity derivatives:

             
 

Oil derivative contracts

    296     2,942  
 

Gas derivative contracts

    18,424     29,115  
           

    18,720     32,057  
           

Current Liabilities—Commodity and interest derivatives:

             
 

Oil derivative contracts

    (25,690 )   (7,443 )
 

Gas derivative contracts

    (7,787 )   (807 )
 

Interest rate derivative contracts

    (16,232 )   (16,228 )
           

    (49,709 )   (24,478 )
           

Commodity and interest derivatives:

             
 

Gas derivative contracts

    (4,968 )   (524 )
 

Interest rate derivative contracts

    (10,108 )   (26,844 )
           

    (15,076 )   (27,368 )
           
   

Net derivative (liability) asset

  $ (11,454 ) $ 19,824  
           

5. FAIR VALUE MEASUREMENTS

        Fair value is defined as the price that would be received in the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. The FASB has established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

5. FAIR VALUE MEASUREMENTS (Continued)

        The three levels of the fair value hierarchy are as follows:

        Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

        Level 2—Pricing inputs are other than quoted prices in active markets included in level 1, but are either directly or indirectly observable as of the reported date and for substantially the full term of the instrument. Inputs may include quoted prices for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies.

        Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.

        Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of June 30, 2010 (in thousands).

 
  Level 1   Level 2   Level 3   Fair Value
as of
June 30,
2010
 

Assets (Liabilities):

                         
 

Commodity derivative contracts

  $   $ 71,670   $   $ 71,670  
 

Commodity derivative contracts

        (8,774 )       (8,774 )
 

Interest rate derivative contracts

        (43,072 )       (43,072 )

        The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above:

        Commodity Derivative Contracts.    The Company's commodity derivative instruments consist primarily of swaps, collars and option contracts for oil and natural gas. The Company values the derivative contracts using industry standard models, based on an income approach, which consider various assumptions including quoted forward prices and contractual prices for the underlying commodities, time value and volatility factors, as well as other relevant economic measures. Substantially all of the assumptions can be observed throughout the full term of the contracts, can be derived from observable data or are supportable by observable levels at which transactions are executed in the marketplace and are therefore designated as level 2 within the fair value hierarchy. The discount rates used in the assumptions include a component of non-performance risk. The Company utilizes the relevant counterparty valuations to assess the reasonableness of the calculated fair values.

        Interest Rate Derivative Contracts.    The Company's interest rate swap was valued using an industry standard model, based on a income approach, that utilizes quoted forward prices for interest rates, time value and contractual interest rates per the swap contract. The discount rates used in the assumption

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(UNAUDITED)

5. FAIR VALUE MEASUREMENTS (Continued)


include a component of non-performance risk. The interest rate swap is designated as level 2 within the fair value hierarchy. The Company utilizes the relevant counterparties valuations to assess the reasonableness of the calculated fair values.

        Fair Value of Financial Instruments.    The Company's financial instruments consist primarily of cash and cash equivalents, accounts receivable and payable, derivatives (discussed above) and long-term debt. The carrying values of cash equivalents and accounts receivable and payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company's revolving credit facility approximated fair value because the interest rate of the facility is variable. The fair value of the second lien term loan facility and the senior notes listed in the tables below were derived from available market data. This disclosure does not impact our financial position, results of operations or cash flows (in thousands).

 
  December 31, 2009   June 30, 2010  
 
  Carrying
Value
  Estimated
Fair Value
  Carrying
Amount
  Estimated
Fair Value
 

Revolving credit agreement

  $ 57,860   $ 57,860   $ 26,000   $ 26,000  

Second lien term loan

    494,485     445,037     463,776     408,123  

11.50% senior notes

    142,684     142,545     142,973     149,775  

6. ASSET RETIREMENT OBLIGATIONS

        The Company's asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut-in properties (including removal of certain onshore and offshore facilities) at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company's credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method.

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(UNAUDITED)

6. ASSET RETIREMENT OBLIGATIONS (Continued)

        The following table summarizes the activities for the Company's asset retirement obligations for the six months ended June 30, 2009 and 2010 (in thousands):

 
  Six Months
Ended
June 30, 2009
  Six Months
Ended
June 30, 2010
 

Asset retirement obligations at beginning of period

  $ 80,579   $ 92,985  

Revisions of estimated liabilities

    202     270  

Liabilities incurred

    6,164     2,537  

Liabilities settled

    (229 )   (1,257 )

Disposition of properties

    (2,993 )   (5,292 )

Accretion expense

    2,745     3,131  
           
 

Asset retirement obligations at end of period

    86,468     92,374  

Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)

    (1,075 )   (1,000 )
           
   

Long-term asset retirement obligations

  $ 85,393   $ 91,374  
           

7. CAPITAL STOCK

        The Company has 61.3 million shares of common stock issued or reserved for issuance at June 30, 2010. At June 30, 2010, the Company has 54.8 million common shares issued and outstanding, of which 2.7 million shares are restricted stock granted under the Company's 2005 stock incentive plan. At June 30, 2010, the Company had approximately 2.7 million options outstanding and 3.5 million shares available to be issued pursuant to awards under its stock incentive plans, including the 2008 Employee Stock Purchase Plan.

8. SHARE-BASED PAYMENTS

        The Company has granted options to directors, certain employees and officers of the Company, other than its CEO, under its 2000 and 2005 Stock Plans (the "Stock Plans"). As of June 30, 2010, there are a total of 2,690,988 options outstanding with a weighted average exercise price of $9.31 ($6.00 to $20.00). The options vest over a four year period, with 20% vesting on the grant date and 20% vesting on each subsequent anniversary of the grant date. The options typically have a maximum life of 10 years. The options will generally vest upon a change in control of the Company. Unexercised options expire when an option holder elects to terminate employment or if the Company terminates the holder's employment for misconduct. If the Company terminates a holder's employment other than for misconduct, unvested options generally terminate and the holder has a limited period of time within which to exercise vested options, unless the award agreement provides otherwise.

        Effective February 1, 2009, the Company implemented a non-compensatory 2008 Employee Stock Purchase Plan (the "ESPP"), which has been approved by the Company's Board of Directors and shareholders. In connection with the approval of the ESPP, the Board authorized 1.5 million shares of common stock to be issued under the ESPP. Participation in the ESPP is open to all employees, other than executive officers, who meet limited qualifications. Under the terms of the ESPP, employees are able to purchase Company stock at a 5% discount as determined by the fair market value of the

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(UNAUDITED)

8. SHARE-BASED PAYMENTS (Continued)


Company's stock on the last trading day of each purchase period. Individual employees are limited to $25,000 of common stock purchased in any calendar year.

        As of June 30, 2010, there were a total of 2,730,582 shares of restricted stock outstanding under the Company's 2005 stock incentive plan, including 859,517 shares granted to its CEO. The restricted shares generally have a requisite service period of four years. The grant date fair value of restricted stock subject to service conditions only is determined by the Company's closing stock price on the day prior to the date of grant. The vesting of 1,521,915 shares is also subject to market conditions based on the Company's total shareholder return in comparison to peer group companies for each calendar year. The weighted-average fair value of the restricted shares subject to market conditions was derived using a Monte Carlo technique. The weighted average fair value of 989,520 awards with market conditions granted in February 2010 was estimated to be $10.65 per share. The estimated grant date fair values of restricted share awards are recognized as expense over the requisite service periods. As of June 30, 2010, there was $0.4 million of total unrecognized compensation cost related to stock options, which is expected to be amortized over a weighted-average period of 0.7 years, and $20.3 million of total unrecognized compensation cost related to restricted stock, which is expected to be amortized over a weighted-average period of 3.3 years.

        The Company recognized total share-based compensation costs as follows (in thousands):

 
  Three Months
Ended
June 30,
  Six Months
Ended
June 30,
 
 
  2009   2010   2009   2010  

General and administrative expense

  $ 910   $ 1,720   $ 2,030   $ 3,360  

Oil and natural gas production expense

    190     340     320     580  
                   
 

Total share-based compensation costs

    1,100     2,060     2,350     3,940  

Less: share-based compensation costs capitalized

    (456 )   (652 )   (1,156 )   (1,209 )
                   
 

Share-based compensation expensed

  $ 644   $ 1,408   $ 1,194   $ 2,731  
                   

        The following summarizes the Company's stock option activity for the six months ended June 30, 2010:

 
  Options   Weighted
Average
Exercise
Price
 

Outstanding, start of period

    3,301,903   $ 8.92  

Granted

         

Exercised

    (594,315 ) $ 6.96  

Cancelled

    (16,600 ) $ 10.29  
             
 

Outstanding, end of period

    2,690,988   $ 9.31  
             
 

Exercisable, end of period

    2,564,118   $ 8.96  

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

8. SHARE-BASED PAYMENTS (Continued)

        The following summarizes the Company's unvested restricted stock award activity for the six months ended June 30, 2010:

 
  Shares   Weighted
Average
Grant Date
Fair Value
 

Non-vested, start of period

    1,594,156   $ 7.20  

Granted

    1,827,435   $ 11.69  

Vested

    (551,095 ) $ 8.71  

Forfeited

    (139,914 ) $ 11.05  
             
 

Non-vested, end of period

    2,730,582   $ 9.70  
             

9. CONTINGENCIES

        Between June 2003 and April 2005, six lawsuits were filed against the Company and certain other energy companies in Los Angeles County Superior Court by persons who attended Beverly Hills High School or who were or are citizens of Beverly Hills/Century City or visitors to that area during the time period running from the 1930s to date. There are approximately 1,000 plaintiffs (including plaintiffs in two related lawsuits in which the Company has not been named) who claimed to be suffering from various forms of cancer or other illnesses, fear they may suffer from such maladies in the future, or are related to persons who have suffered from cancer or other illnesses. Plaintiffs alleged that exposure to substances in the air, soil and water that originated from either oil-field or other operations in the area were the cause of the cancers and other maladies. The Company has owned an oil and natural gas facility adjacent to the school since 1995. For the majority of the plaintiffs, their alleged exposures occurred before the Company acquired the facility. All cases were consolidated before one judge. Twelve "representative" plaintiffs were selected to have their cases tried first, while all of the other plaintiffs' cases were stayed. In November 2006, the judge entered summary judgment in favor of all defendants in the test cases, including the Company. The judge dismissed all claims by the test case plaintiffs on the grounds that they offered no evidence of medical causation between the alleged emissions and the plaintiffs' alleged injuries. Plaintiffs appealed the ruling. A decision on the appeal is expected in late 2010 or 2011. The Company vigorously defended the actions, and will continue to do so until they are resolved. Certain defendants have made claims for indemnity for events occurring prior to 1995, which the Company is disputing. The Company cannot predict the cost of these indemnity claims at the present time.

        One of the Company's insurers currently is paying for the defense of these lawsuits under a reservation of its rights. Three other insurers that provided insurance coverage to the Company (the "Declining Insurers") took the position that they were not required to provide coverage for losses arising out of, or to defend against, the lawsuits because of a pollution exclusion contained in their policies. In February 2006, the Company filed a declaratory relief action against the Declining Insurers in Santa Barbara County Superior Court seeking a determination that those insurers have a duty to defend the Company in the lawsuits. Two of the three Declining Insurers settled with the Company.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

9. CONTINGENCIES (Continued)


The third Declining Insurer disputed the Company's position and in November 2007 the Santa Barbara Court granted that insurer's motion for summary judgment, in part on the basis that the pollution exclusion provision in the policy did not require that insurer to provide a defense for the Company. That decision was upheld on appeal. The Company has no reason to believe that the insurer currently providing defense of these actions will cease providing such defense. If it does, and the Company is unsuccessful in enforcing its rights in any subsequent litigation, the Company may be required to bear the costs of the defense, and those costs may be material. If it ultimately is determined that the pollution exclusion or another exclusion contained in one or more of the Company's policies applies, the Company will not have the protection of those policies with respect to any damages or settlement costs ultimately incurred in the lawsuits.

        The Company has not accrued for a loss contingency relating to the Beverly Hills litigation because the Company believes that, although unfavorable outcomes in the proceedings may be reasonably possible, the Company does not consider them to be probable or reasonably estimable. If one or more of these matters are resolved in a manner adverse to the Company, and if insurance coverage is determined not to be applicable, their impact on the Company's results of operations, financial position and/or liquidity could be material.

        In 2004 the California State Lands Commission (the "SLC") initiated an audit of the Company's royalty payments for the period from August 1, 1997 through December 31, 2003 on oil and gas produced from the South Ellwood Field, State Leases 3120 and 3240 (the "Leases"). The audit period was subsequently extended through September 2009. In December 2009, the Company was notified that the SLC's audit for the period January 2004 through September 2009 (the "Audit Period") indicates that the Company underpaid royalties due on oil and gas production from the Leases during the Audit Period by approximately $5.8 million. Based on the Company's initial review of the SLC's audit contentions and additional historical records, the Company believes that it may have overpaid royalties due on oil and gas production during the Audit Period and for prior periods and may be owed a refund of such overpayments. The Company believes the position of the SLC is without merit and it intends to vigorously contest the audit findings and to enforce its rights for refunds of royalties it may have overpaid during the Audit Period and prior periods. The Company has not accrued any amounts related to the SLC audit contentions or potential refunds.

        In addition, the Company is a party from time to time to other claims and legal actions that arise in the ordinary course of business. The Company believes that the ultimate impact, if any, with respect to these other claims and legal actions will not have a material effect on its consolidated financial position, results of operations or liquidity.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION

        All subsidiaries of the Company other than Ellwood Pipeline Inc. ("Guarantors") have fully and unconditionally guaranteed, on a joint and several basis, the Company's obligations under its 11.50% senior notes. Ellwood Pipeline, Inc. is not a Guarantor (the "Non-Guarantor Subsidiary"). The condensed consolidating financial information for prior periods has been revised to reflect the guarantor and non-guarantor status of the Company's subsidiaries as of June 30, 2010. All Guarantors are 100% owned by the Company. Presented below are the Company's condensed consolidating balance sheets, statements of operations and statements of cash flows as required by Rule 3-10 of Regulation S-X of the Securities Exchange Act of 1934.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)


CONDENSED CONSOLIDATING BALANCE SHEETS
AT DECEMBER 31, 2009 (Unaudited)
(in thousands)

 
  Venoco, Inc.   Guarantor
Subsidiaries
  Non-Guarantor
Subsidiary
  Eliminations   Consolidated  

ASSETS

                               

CURRENT ASSETS:

                               
 

Cash and cash equivalents

  $ 418   $ 1   $   $   $ 419  
 

Accounts receivable

    29,453     3,939     461         33,853  
 

Inventories

    5,813     326             6,139  
 

Prepaid expenses and other current assets

    4,276                 4,276  
 

Income taxes receivable

    3,116                 3,116  
 

Deferred income taxes

    8,400                 8,400  
 

Commodity derivatives

    34,611                 34,611  
                       

TOTAL CURRENT ASSETS

    86,087     4,266     461         90,814  
                       
 

PROPERTY, PLANT & EQUIPMENT, NET

    697,270     (80,955 )   3,115         619,430  
 

COMMODITY DERIVATIVES

    18,720                 18,720  
 

INVESTMENTS IN AFFILIATES

    512,074             (512,074 )    
 

OTHER

    10,235     344             10,579  
                       

TOTAL ASSETS

  $ 1,324,386   $ (76,345 ) $ 3,576   $ (512,074 ) $ 739,543  
                       

LIABILITIES AND STOCKHOLDERS' EQUITY

                               

CURRENT LIABILITIES:

                               
 

Accounts payable and accrued liabilities

  $ 43,983   $ 4,726   $   $   $ 48,709  
 

Undistributed revenue payable

    8,146                 8,146  
 

Interest payable

    4,885                 4,885  
 

Commodity and interest derivatives

    49,709                 49,709  
                       

TOTAL CURRENT LIABILITIES:

    106,723     4,726             111,449  
                       

LONG-TERM DEBT

    695,029                 695,029  

COMMODITY AND INTEREST DERIVATIVES

    15,076                 15,076  

ASSET RETIREMENT OBLIGATIONS

    84,925     6,638     922         92,485  

INTERCOMPANY PAYABLES (RECEIVABLES)

    597,129     (549,473 )   (47,656 )        
                       

TOTAL LIABILITIES

    1,498,882     (538,109 )   (46,734 )       914,039  
                       

TOTAL STOCKHOLDERS' EQUITY

    (174,496 )   461,764     50,310     (512,074 )   (174,496 )
                       

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

  $ 1,324,386   $ (76,345 ) $ 3,576   $ (512,074 ) $ 739,543  
                       

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)


CONDENSED CONSOLIDATING BALANCE SHEETS
AT JUNE 30, 2010 (Unaudited)
(in thousands)

 
  Venoco, Inc.   Guarantor
Subsidiaries
  Non-Guarantor
Subsidiary
  Eliminations   Consolidated  

ASSETS

                               

CURRENT ASSETS:

                               
 

Cash and cash equivalents

  $ 2,204   $   $   $   $ 2,204  
 

Accounts receivable

    25,962     528     437         26,927  
 

Inventories

    6,231                 6,231  
 

Prepaid expenses and other current assets

    3,289                 3,289  
 

Income tax receivable

    11,966                 11,966  
 

Commodity derivatives

    39,613                 39,613  
                       

TOTAL CURRENT ASSETS

    89,265     528     437         90,230  
                       
 

PROPERTY, PLANT & EQUIPMENT, NET

    754,101     (182,891 )   6,124         577,334  
 

COMMODITY DERIVATIVES

    32,057                 32,057  
 

INVESTMENTS IN AFFILIATES

    518,122             (518,122 )    
 

OTHER

    9,123     345             9,468  
                       

TOTAL ASSETS

  $ 1,402,668   $ (182,018 ) $ 6,561   $ (518,122 ) $ 709,089  
                       

LIABILITIES AND STOCKHOLDERS' EQUITY

                               

CURRENT LIABILITIES:

                               
 

Accounts payable and accrued liabilities

  $ 36,044   $ 4,996   $   $   $ 41,040  
 

Undistributed revenue payable

    5,274                 5,274  
 

Interest payable

    5,367                 5,367  
 

Commodity and interest derivatives

    24,478                 24,478  
                       

TOTAL CURRENT LIABILITIES:

    71,163     4,996             76,159  
                       

LONG-TERM DEBT

    632,749                 632,749  

COMMODITY AND INTEREST DERIVATIVES

    27,368                 27,368  

ASSET RETIREMENT OBLIGATIONS

    88,874     1,544     956         91,374  

INTERCOMPANY PAYABLES (RECEIVABLES)

    701,075     (653,290 )   (47,785 )        
                       

TOTAL LIABILITIES

    1,521,229     (646,750 )   (46,829 )       827,650  
                       

TOTAL STOCKHOLDERS' EQUITY

    (118,561 )   464,732     53,390     (518,122 )   (118,561 )
                       

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

  $ 1,402,668   $ (182,018 ) $ 6,561   $ (518,122 ) $ 709,089  
                       

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
THREE MONTHS ENDED JUNE 30, 2009 (Unaudited)
(in thousands)

 
  Venoco, Inc.   Guarantor
Subsidiaries
  Non-Guarantor
Subsidiary
  Eliminations   Consolidated  

REVENUES:

                               
 

Oil and natural gas sales

  $ 54,873   $ 7,138   $   $   $ 62,011  
 

Other

    705     5     1,398     (1,305 )   803  
                       
   

Total revenues

    55,578     7,143     1,398     (1,305 )   62,814  
                       

EXPENSES:

                               
 

Oil and natural gas production

    21,816     3,138     585         25,539  
 

Transportation expense

    1,964     24         (1,224 )   764  
 

Depletion, depreciation and amortization

    18,907     1,678     23         20,608  
 

Accretion of asset retirement obligations

    1,264     110     14         1,388  
 

General and administrative, net of amounts capitalized

    7,901     658     81     (81 )   8,559  
                       
   

Total expenses

    51,852     5,608     703     (1,305 )   56,858  
                       

Income (loss) from operations

    3,726     1,535     695         5,956  
                       

FINANCING COSTS AND OTHER:

                               
 

Interest expense, net

    10,691     (1 )   (913 )       9,777  
 

Amortization of deferred loan costs

    738                 738  
 

Interest rate derivative losses (gains), net

    7,953                 7,953  
 

Loss on extinguishment of debt

    582                 582  
 

Commodity derivative losses (gains), net

    50,483                 50,483  
                       
   

Total financing costs and other

    70,447     (1 )   (913 )       69,533  
                       

Equity in subsidiary income

    1,949             (1,949 )    
                       

Income (loss) before income taxes

    (64,772 )   1,536     1,608     (1,949 )   (63,577 )

Income tax provision (benefit)

    (5,295 )   584     611         (4,100 )
                       

Net income (loss)

  $ (59,477 ) $ 952   $ 997   $ (1,949 ) $ (59,477 )
                       

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)


CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
THREE MONTHS ENDED JUNE 30, 2010 (Unaudited)
(in thousands)

 
  Venoco, Inc.   Guarantor
Subsidiaries
  Non-Guarantor
Subsidiary
  Eliminations   Consolidated  

REVENUES:

                               
 

Oil and natural gas sales

  $ 65,571   $ 3,305   $   $   $ 68,876  
 

Other

    1,520     (33 )   1,251     (1,172 )   1,566  
                       
   

Total revenues

    67,091     3,272     1,251     (1,172 )   70,442  
                       

EXPENSES:

                               
 

Oil and natural gas production

    22,563     966     416         23,945  
 

Transportation expense

    4,128     2         (1,085 )   3,045  
 

Depletion, depreciation and amortization

    18,082     525     135         18,742  
 

Accretion of asset retirement obligations

    1,453     76     17         1,546  
 

General and administrative, net of amounts capitalized

    9,167     1,567     115     (87 )   10,762  
                       
   

Total expenses

    55,393     3,136     683     (1,172 )   58,040  
                       

Income (loss) from operations

    11,698     136     568         12,402  
                       

FINANCING COSTS AND OTHER:

                               
 

Interest expense, net

    11,241     (1 )   (942 )       10,298  
 

Amortization of deferred loan costs

    679                 679  
 

Interest rate derivative losses (gains), net

    16,276                 16,276  
 

Commodity derivative losses (gains), net

    (18,560 )               (18,560 )
                       
     

Total financing costs and other

    9,636     (1 )   (942 )       8,693  
                       

Equity in subsidiary income

    1,021             (1,021 )    
                       

Income (loss) before income taxes

    3,083     137     1,510     (1,021 )   3,709  

Income tax provision (benefit)

    (626 )   52     574          
                       

Net income (loss)

  $ 3,709   $ 85   $ 936   $ (1,021 ) $ 3,709  
                       

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)


CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 2009 (Unaudited)
(in thousands)

 
  Venoco, Inc.   Guarantor
Subsidiaries
  Non-Guarantor
Subsidiary
  Eliminations   Consolidated  

REVENUES:

                               
 

Oil and natural gas sales

  $ 103,255   $ 16,187   $   $   $ 119,442  
 

Other

    1,468     27     2,809     (2,616 )   1,688  
                       
   

Total revenues

    104,723     16,214     2,809     (2,616 )   121,130  
                       

EXPENSES:

                               
 

Oil and natural gas production

    43,577     7,630     1,058         52,265  
 

Transportation expense

    4,226     39         (2,455 )   1,810  
 

Depletion, depreciation and amortization

    38,895     4,349     47         43,291  
 

Accretion of asset retirement obligations

    2,482     236     27         2,745  
 

General and administrative, net of amounts capitalized

    15,332     1,225     161     (161 )   16,557  
                       
   

Total expenses

    104,512     13,479     1,293     (2,616 )   116,668  
                       

Income (loss) from operations

    211     2,735     1,516         4,462  
                       

FINANCING COSTS AND OTHER:

                               
 

Interest expense, net

    22,751     (4 )   (1,792 )       20,955  
 

Amortization of deferred loan costs

    1,473                 1,473  
 

Interest rate derivative losses (gains), net

    8,900                 8,900  
 

Loss on extinguishment of debt

    582                 582  
 

Commodity derivative losses (gains), net

    1,924                 1,924  
                       
   

Total financing costs and other

    35,630     (4 )   (1,792 )       33,834  
                       

Equity in subsidiary income

    3,749             (3,749 )    
                       

Income (loss) before income taxes

    (31,670 )   2,739     3,308     (3,749 )   (29,372 )

Income tax provision (benefit)

    2,602     1,041     1,257         4,900  
                       

Net income (loss)

  $ (34,272 ) $ 1,698   $ 2,051   $ (3,749 ) $ (34,272 )
                       

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)


CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 2010 (Unaudited)
(in thousands)

 
  Venoco, Inc.   Guarantor
Subsidiaries
  Non-Guarantor
Subsidiary
  Eliminations   Consolidated  

REVENUES:

                               
 

Oil and natural gas sales

  $ 141,052   $ 10,325   $   $   $ 151,377  
 

Other

    2,216     3     2,510     (2,343 )   2,386  
                       
   

Total revenues

    143,268     10,328     2,510     (2,343 )   153,763  
                       

EXPENSES:

                               
 

Oil and natural gas production

    43,089     3,154     774         47,017  
 

Transportation expense

    6,846     12         (2,170 )   4,688  
 

Depletion, depreciation and amortization

    36,647     1,803     266         38,716  
 

Accretion of asset retirement obligations

    2,898     199     34         3,131  
 

General and administrative, net of amounts capitalized

    17,933     2,192     219     (173 )   20,171  
                       
   

Total expenses

    107,413     7,360     1,293     (2,343 )   113,723  
                       

Income (loss) from operations

    35,855     2,968     1,217         40,040  
                       

FINANCING COSTS AND OTHER:

                               
 

Interest expense, net

    22,286     (1 )   (1,863 )       20,422  
 

Amortization of deferred loan costs

    1,356                 1,356  
 

Interest rate derivative losses (gains), net

    25,800                 25,800  
 

Commodity derivative losses (gains), net

    (55,035 )               (55,035 )
                       
     

Total financing costs and other

    (5,593 )   (1 )   (1,863 )       (7,457 )
                       

Equity in subsidiary income

    3,750             (3,750 )    
                       

Income (loss) before income taxes

    45,198     2,969     3,080     (3,750 )   47,497  

Income tax provision (benefit)

    (2,499 )   1,128     1,171         (200 )
                       

Net income (loss)

  $ 47,697   $ 1,841   $ 1,909   $ (3,750 ) $ 47,697  
                       

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
SIX MONTHS ENDED JUNE 30, 2009 (Unaudited)
(in thousands)

 
  Venoco, Inc.   Guarantor
Subsidiaries
  Non-Guarantor
Subsidiary
  Eliminations   Consolidated  

CASH FLOWS FROM OPERATING ACTIVITIES:

                               
 

Net cash provided by (used in) operating activities

  $ 28,882   $ 15,052   $ 3,326   $   $ 47,260  

CASH FLOWS FROM INVESTING ACTIVITIES:

                               
 

Expenditures for oil and natural gas properties

    (107,973 )   (8,698 )           (116,671 )
 

Acquisitions of oil and natural gas properties

    (21,575 )               (21,575 )
 

Expenditures for property and equipment and other

    (1,655 )   527             (1,128 )
 

Proceeds from sale of oil and natural gas properties

        200,060             200,060  
                       
   

Net cash provided by (used in) investing activities

    (131,203 )   191,889             60,686  

CASH FLOWS FROM FINANCING ACTIVITIES:

                               
 

Net proceeds from (repayments of) intercompany borrowings

    210,267     (206,941 )   (3,326 )        
 

Proceeds from long-term debt

    102,394                 102,394  
 

Principal payments on long-term debt

    (209,016 )               (209,016 )
 

Payments for deferred loan costs

    (275 )               (275 )
 

Proceeds from Employee Stock Purchase Plan

    155                 155  
 

Stock from disgorgement of stock sale profits

    15                 15  
 

Proceeds from exercise of stock options

    174                 174  
                       
   

Net cash provided by (used in) financing activities

    103,714     (206,941 )   (3,326 )       (106,553 )
                       
 

Net increase (decrease) in cash and cash equivalents

    1,393                 1,393  
 

Cash and cash equivalents, beginning of period

    190     1             191  
                       
 

Cash and cash equivalents, end of period

  $ 1,583   $ 1   $   $   $ 1,584  
                       

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)


CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
SIX MONTHS ENDED JUNE 30, 2010 (Unaudited)
(in thousands)

 
  Venoco, Inc.   Guarantor
Subsidiaries
  Non-Guarantor
Subsidiary
  Eliminations   Consolidated  

CASH FLOWS FROM OPERATING ACTIVITIES:

                               
 

Net cash provided by (used in) operating activities

  $ 42,727   $ 8,977   $ 3,404   $   $ 55,108  

CASH FLOWS FROM INVESTING ACTIVITIES:

                               
 

Expenditures for oil and natural gas properties

    (82,576 )   (4,878 )   (3,275 )       (90,729 )
 

Acquisitions of oil and natural gas properties

    (2,232 )               (2,232 )
 

Expenditures for property and equipment and other

    (1,309 )   (1 )           (1,310 )
 

Proceeds from sale of oil and natural gas properties

        99,445             99,445  
                       
   

Net cash provided by (used in) investing activities

    (86,117 )   94,566     (3,275 )       5,174  

CASH FLOWS FROM FINANCING ACTIVITIES:

                               
 

Net proceeds from (repayments of) intercompany borrowings

    103,673     (103,544 )   (129 )        
 

Proceeds from long-term debt

    75,000                 75,000  
 

Principal payments on long-term debt

    (137,570 )               (137,570 )
 

Payments for deferred loan costs

    (225 )               (225 )
 

Proceeds from Employee Stock Purchase Plan

    196                 196  
 

Proceeds from exercise of stock options

    4,102                 4,102  
                       
   

Net cash provided by (used in) financing activities

    45,176     (103,544 )   (129 )       (58,497 )
                       
 

Net increase (decrease) in cash and cash equivalents

    1,786     (1 )           1,785  
 

Cash and cash equivalents, beginning of period

    418     1             419  
                       
 

Cash and cash equivalents, end of period

  $ 2,204   $   $   $   $ 2,204  
                       

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Item 2.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        The following discussion and analysis should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in our Annual Report on Form 10-K for the year ended December 31, 2009 as well as with the financial statements and related notes and the other information appearing elsewhere in this report. As used in this report, unless the context otherwise indicates, references to "we," "our," "ours," and "us" refer to Venoco, Inc. and its subsidiaries collectively.

Overview

        We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. Our strategy is to grow through exploration, exploitation and development projects we believe to have the potential to add significant reserves on a cost-effective basis and through selective acquisitions of underdeveloped properties. Our average net production was 18,190 BOE/d in the second quarter of 2010, compared to 20,434 BOE/d in the second quarter of 2009 and 19,384 BOE/d in the first quarter of 2010. Excluding production from our producing properties in Texas, which we sold in a series of transactions during the second quarter of 2010, our average net production was 17,608 BOE/d in the second quarter of 2010, compared to 18,671 BOE/d in the second quarter of 2009 and 18,096 BOE/d in the first quarter of 2010.

        In the execution of our strategy, our management is principally focused on economically developing additional reserves of oil and natural gas and on maximizing production levels through exploration, exploitation and development activities in a manner consistent with preserving adequate liquidity and financial flexibility.

Capital Expenditures

        We have developed an active capital expenditure program to take advantage of our extensive inventory of drilling prospects and other projects. Our development, exploitation and exploration capital expenditure budget for 2010 is $220 million, of which approximately $96.2 million was expended in the first six months of 2010. We expect to spend approximately 49% of the budgeted amount on projects in the Sacramento Basin, 29% on projects in producing Southern California fields, and 22% on onshore Monterey shale projects in Southern California. The aggregate levels of capital expenditures for 2010, and the allocation of those expenditures, are dependent on a variety of factors, including the availability of capital resources to fund the expenditures and changes in our business assessments as to where our capital can be most profitably deployed. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from our estimates. The following summarizes certain significant aspects of our 2010 capital spending program:

Southern California—Exploitation and Development

        In the West Montalvo field, we completed two wells during the first quarter of 2010 that were spud toward the end of 2009. Since acquiring the field in May 2007, we have pursued an aggressive workover, recompletion and return to production program that has resulted in significant production gains. The field has not been fully delineated offshore or fully developed onshore and we continue to evaluate our drilling results and refine our development program for the coming years. Our 2010 capital expenditure budget includes plans to drill one additional well at West Montalvo later in the year.

        In the Sockeye field, we completed our hydraulic fracture of the E-8 well during the first quarter, and also completed a dual completion well that produces from the Monterey shale formation and injects into the Lower Topanga formation, increasing the sweep of the waterflood in that zone. A

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planned redrill of an inactive well that will target the Monterey shale formation was delayed as a result of a drilling moratorium imposed by the Secretary of the U.S. Department of the Interior. That moratorium has been lifted for wells drilled from Platform Gail and we plan to proceed with the redrill later in 2010 or early 2011. We also have a number of development opportunities in the South Ellwood field. We performed six recompletions at South Ellwood during the first six months of 2010. During the second half of the year, we plan to advance the permitting process for three of the five proved undeveloped locations on our existing leases and perform the facilities work in order to begin drilling those locations in 2011.

        In addition, our subsidiary Ellwood Pipeline, Inc. is pursuing the permits necessary to build a common carrier pipeline that would allow us to transport our oil from the South Ellwood field to refiners without the use of a barge or the marine terminal we currently use. We anticipate that approval hearings for the project will be held during the second half of 2010. While we believe the pipeline should be approved, the outcome of these hearings cannot be predicted. Pending completion of the pipeline, we expect to primarily use a double-hulled barge to transport oil production from the field, although we will use an older, single-hulled barge while modifications are made to the double-hulled barge necessary to address permitting requirements. We expect those modifications to be completed late in the third quarter of 2010.

        We also continue to pursue a major lease extension in the South Ellwood field. The lease extension would effectively double the size of the existing lease area. Development of the lease extension area can be accomplished from the field's existing platform. However, we may withdraw the application for the lease extension project if we determine that continuing the permitting process for that project is likely to significantly impede the permitting of the pipeline project.

Sacramento Basin—Exploitation and Development

        In the Sacramento Basin, we continue to pursue our infill drilling program in the greater Grimes and Willows fields. We expect to drill approximately 100 wells in 2010 and perform approximately 250 recompletions. During the first six months of 2010, we spud 46 wells and performed 103 recompletions.

        We continue to test and evaluate potential downspacing opportunities in the basin as well as new methods of improving productivity and reducing drilling costs. We also continue to pursue our hydraulic fracturing program in the basin. We plan to fracture approximately ten wells in 2010, of which six were fractured in the first six months. We have been encouraged by the results and continue to analyze those results in order to optimize future fracture simulations in the basin.

Texas—Exploitation and Development

        In anticipation of the sale of our Texas producing assets (see "—Acquisitions and Divestitures"), we did not invest any significant capital in Texas during the first six months of 2010.

Onshore Monterey Shale Activities

        In 2006, we began actively leasing onshore acreage in Southern California targeting the Monterey shale, a Miocene age strata. Our leasing has focused on areas where we believe the Monterey shale will produce light, sweet oil, and where the quality and depth of the Monterey shale is expected to be advantageous. Our 2010 budget devotes approximately 22%, or $48 million, to activities targeting the onshore Monterey shale formation. The budgeted expenditures include drilling ten gross wells, aggressively adding to our acreage position, and acquiring 3D seismic data. Our onshore Monterey shale acreage position is approximately 155,000 gross and 108,000 net acres. An additional 60,000 gross and 50,000 net acres with Monterey shale production or potential are held by production. We spud five onshore Monterey shale wells during the first six months of the year. The five wells spud to date have been vertical test wells, four of which are in various stages of drilling or evaluation. One well has been

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temporarily abandoned and we plan to evaluate it as a water disposal well. The initial vertical wells are designed to provide scientific information which we will use to evaluate the specific prospect area, as well as individual zones in the wellbore that are prospective for drilling horizontal wells. Information developed from cutting cores in these vertical wells and analysis of those cores will be used to correlate our petrophysical model with data from historical well logs in the area. We expect the testing and evaluation process to last several months for each test well.

Acquisitions and Divestitures

        Sale of Texas Assets.    We sold our producing assets in Texas in a series of transactions that were completed in the second quarter of 2010 to multiple purchasers for aggregate net proceeds of $99.4 million (after closing adjustments and related expenses). We used the proceeds to repay $66.9 million of principal on the revolving credit facility and $30.7 million of principal on the second lien term loan. We retained our 22.3% reversionary working interest in the Hastings Complex.

        The Texas properties sold comprised 7.2% of our proved reserves at December 31, 2009 or 7.1 MMBOE and contributed approximately 930 BOE/d to our production during the first six months of 2010.

        Sacramento Basin Asset Acquisition.    In June 2009, we closed on the acquisition of certain natural gas producing properties in the Sacramento Basin for approximately $21.4 million.

        Hastings Complex Sale.    In February 2009, we completed the sale of our principal interests in the Hastings Complex to Denbury Resources,  Inc. for approximately $197.7 million.

        Other.    We have an active acreage acquisition program and we regularly engage in acquisitions (and, to a lesser extent, dispositions) of oil and natural gas properties, primarily in and around our existing core areas of operations.

Trends Affecting our Results of Operations

        Oil and Natural Gas Prices.    Historically, prices received for our oil and natural gas production have been volatile and unpredictable, and that volatility is expected to continue. Changes in the market prices for oil and natural gas directly impact many aspects of our business, including our financial condition, revenues, results of operations, liquidity, rate of growth, the carrying value of our oil and natural gas properties and borrowing capacity under our revolving credit facility, all of which depend in part upon those prices. For example, due primarily to lower commodities prices, our revenues from oil and gas sales and cash flow from operations declined 52% and 44%, respectively, in 2009 compared to 2008. We employ a hedging strategy in order to reduce the variability of the prices we receive for our production and provide a minimum revenue stream. As of July 30, 2010 we had hedge contract floors covering approximately 93% of our 2010 annual production guidance and a significant portion of our expected production in 2011. We have also begun to secure hedge contracts for our 2012 production. All of our derivatives counterparties are members, or affiliates of members, of our revolving credit facility syndicate. See "Quantitative and Qualitative Disclosures About Market Risk—Commodity Derivative Transactions" for further details concerning our hedging activities.

        Expected Production.    In 2010, we intend to devote significant effort to the development of our robust inventory of oil projects at our Southern California properties. Because some of these projects will require significant time for implementation, much of the production growth we expect from those projects will not be realized until after 2010. As a result of this and the sale of our producing assets in Texas, we expect our average daily production to decrease slightly from 2009 levels to 19,250 BOE/d for 2010. We began the year with one drilling rig operating in the Sacramento Basin and increased to a four-rig program during the first quarter of the year, and plan to operate with four drilling rigs for the remainder of the year. The increased activity in the basin will partially offset the production lost with

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the divestiture of our Texas properties; however, similar to our projects in Southern California, a significant portion of the production growth resulting from a four-rig program in the Sacramento Basin will be experienced later in 2010 and 2011. Our annual production estimate assumes a capital expenditure budget for 2010 of $220 million, which could be reduced if we do not complete one or more capital raising transactions. Additional uncertainties relating to our expectations for future production rates include those associated with third party services, oil and natural gas prices, events resulting in unexpected downtime, permitting issues, drilling success rates, pipeline capacity and other factors, including those referenced in the "Risk Factors" section of our Annual Report on Form 10-K for the year ended December 31, 2009.

        Production Expenses.    Production expenses consist of lease operating expenses ("LOE") and production and property taxes. LOE per BOE of $12.78 for the first six months of 2010 is relatively consistent with our full year 2009 results of $12.65 per BOE. We expect our 2010 LOE per BOE to increase slightly relative to the full year 2009 results due to our expected focus on oil projects, which tend to have higher operating costs than natural gas projects. Production and property taxes per BOE decreased to $1.05 per BOE for the first six months of 2010 from $1.35 per BOE for the full year 2009. For the full year 2010, we expect production/property taxes to increase slightly on a per BOE basis compared to our 2009 results. Our expectations with respect to future expenses are subject to numerous risks and uncertainties, including those described and referenced in the preceding paragraph.

        General and Administrative Expenses.    General and administrative expenses increased slightly from $4.63 per BOE for the full year 2009 (excluding share-based compensation charges of $0.28 per BOE), to $4.93 per BOE (excluding share-based compensation charges of $0.63 per BOE and one-time charges of $0.37 per BOE for severance payments resulting from the sale of our Texas producing properties) in the first six months of 2010. Excluding share-based compensation charges and one-time severance charges, on a per BOE basis, we expect our 2010 G&A costs to be similar to our 2009 results. As with our production expenses, our expectations with respect to G&A costs are subject to numerous risks and uncertainties.

        Depreciation, Depletion and Amortization (DD&A).    DD&A for the first six months of 2010 of $11.39 per BOE was flat with full year 2009 DD&A of $11.46 per BOE. We expect our 2010 DD&A expenses to increase slightly on a per BOE basis compared to our 2009 results. As with production and G&A expenses, our expectations with respect to DD&A expenses are subject to numerous risks and uncertainties.

        Unrealized Derivative Gains and Losses.    Unrealized gains and losses result from mark-to-market valuations of derivative positions that are not accounted for as cash flow hedges and are reflected as unrealized commodity derivative gains or losses in our income statement. Payments actually due to or from counterparties in the future on these derivatives will typically be offset by corresponding changes in prices ultimately received from the sale of our production. We have incurred significant unrealized gains and losses in recent periods and may continue to incur these types of gains and losses in the future. We may also have significant unrealized interest rate derivative gains and losses in subsequent periods due to changes in market interest rates.

Results of Operations

        The following table reflects the components of our oil and natural gas production and sales prices and sets forth our operating revenues, costs and expenses on a BOE basis for the three and six months ended June 30, 2009 and 2010. This information reflects the actual historical results of our operations.

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No pro forma adjustments have been made for acquisitions and divestitures of oil and gas properties which will affect the comparability of the data below.

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2009   2010   2009   2010  

Production Volume:

                         
 

Oil (MBbls)(1)

    848     700     1,782     1,481  
 

Natural gas (MMcf)

    6,069     5,732     12,198     11,513  
 

MBOE

    1,860     1,655     3,815     3,400  

Daily Average Production Volume:

                         
 

Oil (Bbls/d)

    9,319     7,692     9,845     8,182  
 

Natural gas (Mcf/d)

    66,692     62,989     67,392     63,608  
 

BOE/d

    20,434     18,190     21,077     18,783  

Oil Price per Bbl Produced (in dollars):

                         
 

Realized price

  $ 49.67   $ 67.50   $ 41.67   $ 68.44  
 

Realized commodity derivative gain (loss)

    (0.30 )   (1.54 )   4.88     (1.46 )
                   
 

Net realized price

  $ 49.37   $ 65.96   $ 46.55   $ 66.98  
                   

Natural Gas Price per Mcf (in dollars):

                         
 

Realized price

  $ 3.20   $ 4.12   $ 3.81   $ 4.73  
 

Realized commodity derivative gain (loss)

    3.16     1.99     2.51     1.32  
                   
 

Net realized price

  $ 6.36   $ 6.11   $ 6.32   $ 6.05  
                   

Expense per BOE:

                         
 

Lease operating expenses(2)

  $ 12.46   $ 13.65   $ 12.12   $ 12.78  
 

Production and property taxes(2)

    1.27     0.82     1.58     1.05  
 

Transportation expenses

    0.41     1.84     0.47     1.38  
 

Depreciation, depletion and amortization

    11.08     11.32     11.35     11.39  
 

General and administrative expense(3)

    4.60     6.50     4.34     5.93  
 

Interest expense

    5.26     6.22     5.49     6.01  

(1)
Amounts shown are oil production volumes for offshore properties and sales volumes for onshore properties (differences between onshore production and sales volumes are minimal). Revenue accruals are adjusted for actual sales volumes since offshore oil inventories can vary significantly from month to month based on the timing of barge deliveries, oil in tanks and pipeline inventories, and oil pipeline sales nominations.

(2)
Lease operating expenses are combined with property and production taxes to comprise oil and natural gas production expense on the consolidated statements of operations.

(3)
Net of amounts capitalized.

Comparison of Quarter Ended June 30, 2010 to Quarter Ended June 30, 2009

        Oil and Natural Gas Sales.    Oil and natural gas sales increased $6.9 million (11%) to $68.9 million for the quarter ended June 30, 2010 from $62.0 million for the same period in 2009. The increase was primarily due to an increase in realized oil and natural gas prices, partially offset by a decrease in production as described below.

        Oil sales increased by $2.7 million (6%) in the second quarter of 2010 to $45.3 million compared to $42.6 million in the second quarter of 2009. Oil production decreased by 17%, with production of 700 MBbls in the second quarter of 2010 compared to 848 MBbls in the second quarter of 2009. The production decrease was primarily due to the sales of our producing properties in Texas which occurred

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in multiple closings throughout the second quarter of 2010. The Texas properties contributed 92 MBbls during the second quarter of 2009 compared to 35 MBbls in second quarter of 2010. Excluding production from the Texas properties, production decreased by 91 MBbls (12%) from 756 MBbls in the second quarter of 2009 to 665 MBbls in the second quarter of 2010. This decrease is primarily due to scheduled downtime for annual maintenance performed on Platform Gail and Platform Holly in the second quarter of 2010. During 2009, we did not incur scheduled downtime at Platform Gail and we performed the Platform Holly maintenance in July. Our average realized price for oil increased $17.83 (36%) from $49.67 per Bbl in the second quarter of 2009 to $67.50 per Bbl for the second quarter of 2010.

        Natural gas sales increased $4.2 million (21%) in the second quarter of 2010 to $23.6 million compared to $19.4 million in the second quarter of 2009. Natural gas production decreased 6%, with production of 5,732 MMcf in the second quarter of 2010 compared to 6,069 MMcf in the second quarter of 2009. The decrease was due primarily to the sales of our producing properties in Texas which occurred during the second quarter of 2010. The Texas properties contributed 409 MMcf during the second quarter of 2009 compared to 108 MMcf in the second quarter of 2010. Excluding Texas properties, production was relatively flat between quarters at 5,660 MMcf in the second quarter of 2009 compared to 5,624 MMcf in the second quarter of 2010. During the second quarter of 2010, production was also affected by (i) lower drilling and recompletion activity in the Sacramento Basin in the latter part of 2009 and the natural decline of production in the Sacramento Basin and (ii) pipeline maintenance issues affecting one Sacramento Basin field in the second quarter of 2010. During the second quarter of 2009, production was reduced due to a partial shut-in of the Grimes field resulting from pipeline maintenance that occurred from April 21 through June 5, 2009. Our average realized price for natural gas increased $0.92 per Mcf (29%) from $3.20 per Mcf in the second quarter of 2009 to $4.12 per Mcf for the second quarter of 2010.

        Other Revenues.    Other revenues increased by $0.8 million (95%) to $1.6 million in the second quarter of 2010 from $0.8 million in the second quarter of 2009. The increase is primarily due to a new contract, effective April 2010, related to the double-hulled barge that transports oil produced at our South Ellwood field (see "—Transportation Expenses"). The contract allows us to sub-charter the barge and retain the revenues from such activities. The increase in other revenues is the result of sub-charter activities in the second quarter of 2010.

        Production Expenses.    Production expenses, which consist of lease operating expenses ("LOE") and production/property taxes, decreased $1.6 million (6%) to $23.9 million in the second quarter of 2010 from $25.5 million in the second quarter of 2009. The decrease was due primarily to the sales of our producing properties in Texas which occurred throughout the second quarter of 2010. Production expenses attributable to the Texas properties were $2.9 million in the second quarter of 2009 and $0.9 million in the second quarter of 2010. Excluding the Texas properties, production expenses increased slightly (2%) from $22.7 million in the second quarter of 2009 to $23.0 million in the second quarter of 2010. The increase was primarily due to (i) scheduled maintenance performed at Platform Gail and Platform Holly in the second quarter of 2010 and (ii) higher non-recurring well maintenance costs at Platform Gail in the second quarter of 2010. These increases were largely offset by (i) decreases in supplemental property taxes incurred in 2010 as compared to 2009 and (ii) lower non-recurring well maintenance costs incurred at Platform Holly in the second quarter of 2010. On a per unit basis, LOE increased to $13.65 per BOE in the second quarter of 2010 from $12.46 per BOE in the same period in 2009. Excluding the Texas properties, LOE per BOE increased from $12.09 per BOE in the second quarter of 2009 to $13.63 per BOE in the second quarter of 2010. In addition to the factors discussed above, lower production levels realized in the second quarter of 2010 compared to the second quarter of 2009 contributed to the increase on a per unit basis.

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        Transportation Expenses.    Transportation expenses increased $2.2 million (299%) to $3.0 million in the second quarter of 2010 from $0.8 million in the second quarter of 2009. On a per BOE basis, transportation expenses increased $1.43 per BOE, from $0.41 per BOE in the second quarter of 2009 to $1.84 per BOE in the second quarter of 2010. The increase is primarily due to a new contract, effective April 2010, related to the time-charter of a double-hulled barge to transport oil produced from our South Ellwood field. Under that contract we pay a flat day rate, regardless of our usage of the barge, but have the ability to sub-charter the vessel when not in use transporting production from the South Ellwood field (see "—Other Revenues"). We also incurred additional transportation costs from the use of a single-hulled barge during the transition period to the double-hulled barge. We expect that our transportation costs will be higher until the transition to the double-hulled barge is complete, which is expected to occur late in the third quarter of 2010. Additionally, transportation expense for the second quarter of 2009 includes demurrage reimbursements related to the single-hulled barge, which reduced our overall transportation expense for the 2009 quarter.

        Depletion, Depreciation and Amortization (DD&A).    DD&A expense decreased $1.9 million (9%) to $18.7 million in the second quarter of 2010 from $20.6 million in the second quarter of 2009. The decrease is related to (i) a lower amortizable base in the second quarter of 2010 resulting from the application of the net proceeds from the sales of our Texas producing properties and (ii) lower production in the second quarter 2010 compared to the second quarter of 2009. DD&A expense on a per unit basis increased slightly from $11.08 per BOE for the second quarter of 2009 to $11.32 per BOE in the second quarter of 2010.

        Accretion of Abandonment Liability.    Accretion expense increased $0.1 million (11%) to $1.5 million in the second quarter of 2010 from $1.4 million in the second quarter of 2009. The increase is primarily due to accretion from new wells drilled and completed in 2009 and the first six months of 2010.

        General and Administrative (G&A).    The following table summarizes the components of general and administrative expense incurred during the periods indicated (in thousands):

 
  Three Months Ended
June 30,
 
 
  2009   2010  

Other general and administrative costs

  $ 13,980   $ 13,721  

Share-based compensation costs

    910     1,720  

One-time severance costs

        1,254  

General and administrative costs capitalized

    (6,331 )   (5,933 )
           
 

General and administrative expense

  $ 8,559   $ 10,762  
           

        G&A expense increased $2.2 million (26%) to $10.8 million in the second quarter of 2010 from $8.6 million in the second quarter of 2009. The overall increase in G&A costs was primarily due to the following: (i) one-time severance payments of $1.3 million related to the sale of our Texas properties and the related closure of our Texas operations and (ii) non-cash share-based compensation expense of $1.1 million (net of amount capitalized) charged to G&A in the second quarter of 2010 compared to $0.5 million (net of amount capitalized) in the second quarter of 2009. We issued annual restricted stock awards in both the first quarter of 2010 and 2009. The fair value of the awards issued in the 2010 period was significantly greater than the grants in the 2009 period due to the increase in our stock price that occurred between the periods, which contributed to the increase in non-cash share-based compensation expense. Excluding the effect of the non-cash share-based compensation expense and one-time severance charges, G&A expense increased to $5.10 per BOE in the second quarter of 2010 from $4.36 per BOE in the second quarter of 2009. The increase on a per unit basis is primarily the

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result of lower production levels in the second quarter of 2010 compared with the second quarter of 2009.

        Interest Expense, Net.    Interest expense, net of interest income, increased $0.5 million (5%) from $9.8 million in the second quarter of 2009 to $10.3 million in the second quarter of 2010. The increase was primarily the result of higher interest costs related to the 11.50% senior notes outstanding in the second quarter of 2010 compared to the interest costs related to the 8.75% senior notes outstanding during the second quarter of 2009. The increase was partially offset by lower interest costs related to the second lien term loan in the second quarter of 2010 resulting from principal reductions funded by the proceeds of the Texas sales.

        Amortization of Deferred Loan Costs.    Amortization of deferred loan costs remained constant at $0.7 million for both the second quarter of 2009 and the second quarter of 2010.

        Interest Rate Derivative (Gains) Losses, Net.    Changes in the fair value of our interest rate swap derivative instruments resulted in unrealized losses of $11.7 million in the second quarter of 2010 and $2.8 million in the 2009 period. Unrealized interest rate (gains) losses represent the change in the fair value of our interest rate derivative contracts from period to period based on estimated future interest rates at the end of the reporting period. Realized interest rate swap losses were $4.6 million in the second quarter of 2010 compared to realized losses of $5.1 million in the second quarter of 2009.

        Commodity Derivative (Gains) Losses, Net.    The following table sets forth the components of commodity derivative (gains) losses, net in our consolidated statements of operations for the periods indicated (in thousands):

 
  Three Months Ended
June 30,
 
 
  2009   2010  

Realized commodity derivative (gains) losses

  $ (16,288 ) $ (10,345 )

Amortization of commodity derivative premiums

    6,048     5,658  

Unrealized commodity derivative (gains) losses for changes in fair value

    60,723     (13,873 )
           
 

Commodity derivative (gains) losses

  $ 50,483   $ (18,560 )
           

        Realized commodity derivative gains or losses represent the difference between the strike prices in the contracts settled during the period and the ultimate settlement prices. The realized commodity derivative gains in the second quarter of 2010 and the same period in 2009 reflect the settlement of contracts at prices below the relevant strike prices. Unrealized commodity derivative (gains) losses represent the change in the fair value of our open derivative contracts from period to period. Derivative premiums are amortized over the term of the underlying derivative contracts.

        Income Tax Expense (Benefit).    We incurred losses before income taxes in both 2008 and 2009. These losses were a key consideration that led us to provide a valuation allowance against our net deferred tax assets at December 31, 2009 and June 30, 2010 since we could not conclude that it is more likely than not that the net deferred tax assets will be fully realized. As long as we continue to conclude that we have a need for a full valuation allowance against our net deferred tax assets, we likely will not have any income tax expense or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims, or for state income taxes. The income tax benefit we recorded for the three months ended June 30, 2009 primarily relates to the reduction of a portion of the federal AMT expense recorded in the first quarter of 2009 resulting from the sale of the Hastings Complex in February 2009. No income tax expense was recorded for the three months ended June 30, 2010 due to our valuation allowance.

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        Net Income (Loss).    Net income for the second quarter of 2010 was $3.7 million compared to net loss of $59.5 million for the same period in 2009. The change between periods is the result of the items discussed above.

Comparison of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2009

        Oil and Natural Gas Sales.    Oil and natural gas sales increased $32.0 million (27%) to $151.4 million for the six months ended June 30, 2010 from $119.4 million for the same period in 2009. The increase was primarily due to an increase in realized oil and natural gas prices, partially offset by a decrease in production as described below.

        Oil sales increased by $23.9 million (33%) for the first half of 2010 to $96.9 million compared to $73.0 million in the first half of 2009. Oil production decreased by 17%, with production of 1,481 MBbls in the first half of 2010 compared to 1,782 MBbls in the first half of 2009. The production decrease was primarily due to the sale of the Hastings Complex in early February 2009 and the sales of our remaining producing properties in Texas in the second quarter of 2010. The Texas properties (including Hastings) contributed 265 MBbls during the first six months of 2009 compared to 112 MBbls in the first six months of 2010. Excluding production from the Texas properties, production decreased by 148 MBbls (10%) from 1,517 MBbls in the first six months of 2009 to 1,369 MBbls in the first six months of 2010. This decrease is primarily due to (i) lower oil production from the Sockeye field as a result of wells that were taken offline in the first quarter in connection with development activities and (ii) annual maintenance on Platform Gail and Platform Holly resulting in scheduled downtime in the second quarter of 2010. During 2009, we did not incur scheduled downtime at Platform Gail and we performed the annual maintenance at Platform Holly in July. Our average realized price for oil increased $26.77 (64%) from $41.67 per Bbl in the first six months of 2009 to $68.44 per Bbl for the first six months of 2010.

        Natural gas sales increased $8.1 million (17%) in the first half of 2010 to $54.5 million compared to $46.4 million in the first half of 2009. Natural gas production decreased 6%, with production of 11,513 MMcf in the first half of 2010 compared to 12,198 MMcf in the first half of 2009. The decrease was due in large part to the sales of our producing properties in Texas which occurred during the second quarter of 2010. The Texas properties contributed 801 MMcf during the first half of 2009 compared to 341 MMcf in the first half of 2010. Excluding production from the Texas properties, production decreased by 225 MMcf (2%) from 11,397 MMcf in the first half of 2009 to 11,172 MMcf in the first half of 2010. The slight decrease in production is due to (i) lower drilling and recompletion activity in the Sacramento Basin in the latter part of 2009 and natural decline of production in the Sacramento Basin and (ii) pipeline maintenance issues affecting one Sacramento Basin field during the 2010 period. Our average realized price for natural gas increased $0.92 per Mcf (24%) from $3.81 per Mcf in the first half of 2009 to $4.73 per Mcf for the first half of 2010.

        Other Revenues.    Other revenues increased by $0.7 million (41%) to $2.4 million in the first half of 2010 from $1.7 million in the first half of 2009. The increase is primarily due to a new contract, effective April 2010, related to the double-hulled barge that transports oil produced at our South Ellwood field (see "—Transportation Expenses"). The contract allows us to sub-charter the barge and retain the revenues from such activities. The increase in other revenues is the result of sub-charter activities in the first half of 2010.

        Production Expenses.    Production expenses, which consist of lease operating expenses ("LOE") and production/property taxes, decreased $5.3 million (10%) to $47.0 million in the first half of 2010 from $52.3 million in the first half of 2009. The decrease was primarily due to the sale of the Hastings Complex in early February 2009 and the sale of our remaining Texas properties in the second quarter of 2010. Production expenses attributable to the Texas properties (including Hastings) were $7.5 million in the first half of 2009 and $3.4 million in the first half of 2010. Excluding the Texas properties,

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production expenses decreased by $1.2 million (3%) from $44.8 million in the first half of 2009 to $43.6 million in the first half of 2010. The decrease was due to (i) lower supplemental property taxes incurred in 2010 as compared to 2009 and (ii) lower non-recurring well maintenance costs at Platform Holly in the first half of 2010 compared to the first half of 2009. These decreases were partially offset by (i) higher costs related to annual maintenance performed at Platform Gail and Platform Holly in the second quarter of 2010 and (ii) higher non-recurring well maintenance costs at Platform Gail in the first half of 2010. On a per unit basis, LOE increased from $12.12 per BOE in the first half of 2009 to $12.78 per BOE in the first half of 2010. Excluding the Hastings and Texas sales, LOE per BOE increased from $11.65 per BOE in the first half of 2009 to $12.60 per BOE in the first half of 2010. The increase on a per BOE basis is the result of decreased production levels in the first half of 2010 compared to the first half of 2009.

        Transportation Expenses.    Transportation expenses increased $2.9 million (159%) to $4.7 million in the first half of 2010 from $1.8 million in the first half of 2009. On a per BOE basis, transportation expenses increased $0.91 per BOE, from $0.47 per BOE in the first half of 2009 to $1.38 per BOE in the first half of 2010. The increase is primarily due to a new transportation contract, effective April 2010, related to the time-charter of a double-hulled barge to transport oil produced from our South Ellwood field. Under that contract we pay a flat day rate, regardless of our usage of the barge, but have the ability to sub-charter the vessel when it is not in use transporting production from the South Ellwood field (see "—Other Revenues"). We also incurred additional transportation costs from the use of the single-hulled barge during the transition period from that barge to the double-hulled barge. We expect that our transportation costs will be higher until the transition to the double-hulled barge is complete, which is expected to occur late in the third quarter of 2010. Additionally, transportation expense for the first half of 2009 includes demurrage reimbursements related to the single-hulled barge, which reduced our overall transportation expense for the 2009 period.

        Depletion, Depreciation and Amortization (DD&A).    DD&A expense decreased $4.6 million (11%) to $38.7 million in the first half of 2010 from $43.3 million in the first half of 2009. The decrease is related to (i) a lower amortizable base in the second quarter of 2010 resulting from the application of the net proceeds from the sale of our Texas producing properties and (ii) lower production in the first half of 2010 compared to the first half of 2009. DD&A expense on a per unit basis remained relatively constant at $11.39 per BOE for the first half of 2010 compared to $11.35 per BOE in the first half of 2009.

        Accretion of Abandonment Liability.    Accretion expense increased $0.4 million (14%) to $3.1 million in the first half of 2010 from $2.7 million in the first half of 2009. The increase is primarily due to accretion from new wells drilled and completed in 2009 and the first half of 2010.

        General and Administrative (G&A).    The following table summarizes the components of general and administrative expense incurred during the periods indicated (in thousands):

 
  Six Months Ended
June 30,
 
 
  2009   2010  

Other general and administrative costs

  $ 27,879   $ 27,438  

Share-based compensation costs

    2,030     3,360  

One-time severance costs

        1,254  

General and administrative costs capitalized

    (13,352 )   (11,881 )
           
 

General and administrative expense

  $ 16,557   $ 20,171  
           

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        G&A expense increased $3.6 million (22%) to $20.2 million in the first half of 2010 from $16.6 million in the first half of 2009. The overall increase in G&A costs was primarily due to the following: (i) G&A costs capitalized in the first half of 2010 were lower than the amount capitalized in the first half of 2009 due to lower levels of drilling activity in the first quarter of 2010, (ii) one-time severance payments of $1.3 million related to the sale of our Texas properties and the related closure of our Texas operations and (iii) non-cash share-based compensation expense of $2.2 million (net of amount capitalized) charged to G&A in the first half of 2010 compared to $0.9 million (net of amount capitalized) in the first half of 2009. We issued annual restricted stock awards in both the first quarter of 2010 and 2009. The fair value of the awards issued in the 2010 period was significantly greater than the grants in the 2009 period due to the increase in our stock price between the periods, which contributed to the increase in non-cash share-based compensation expense. Excluding the effect of the non-cash share-based compensation expense and one-time severance charges, G&A expense increased to $4.93 per BOE in the first half of 2010 from $4.11 per BOE in the first half of 2009. The increase on a per unit basis is primarily the result of lower production levels in the first half of 2010 compared with the first half of 2009.

        Interest Expense, Net.    Interest expense, net of interest income, remained relatively constant at $21.0 million in the first half of 2009 compared to $20.4 million in the first half of 2010.

        Amortization of Deferred Loan Costs.    Amortization of deferred loan costs remained relatively constant at $1.5 million in the first half of 2009 and $1.4 million in the first half of 2010.

        Interest Rate Derivative (Gains) Losses, Net.    Changes in the fair value of our interest rate swap derivative instruments resulted in unrealized losses of $16.7 million in the first half of 2010 and unrealized gains of $0.2 million in the 2009 period. Unrealized interest rate (gains) losses represent the change in the fair value of our interest rate derivative contracts from period to period based on estimated future interest rates at the end of the reporting period. Realized interest rate swap losses were $9.1 million in both the first half of 2010 and the first half of 2009.

        Commodity Derivative (Gains) Losses, Net.    The following table sets forth the components of commodity derivative (gains) losses, net in our consolidated statements of operations for the periods indicated (in thousands):

 
  Six Months Ended
June 30,
 
 
  2009   2010  

Realized commodity derivative (gains) losses

  $ (47,073 ) $ (13,006 )

Amortization of commodity derivative premiums

    10,663     11,315  

Unrealized commodity derivative (gains) losses for changes in fair value

    38,334     (53,344 )
           
 

Commodity derivative (gains) losses

  $ 1,924   $ (55,035 )
           

        Realized commodity derivative gains or losses represent the difference between the strike prices in the contracts settled during the period and the ultimate settlement prices. The realized commodity derivative gains in both the first half of 2010 and the first half of 2009 reflect the settlement of contracts at prices below the relevant strike prices. Unrealized commodity derivative (gains) losses represent the change in the fair value of our open derivative contracts from period to period. Derivative premiums are amortized over the term of the underlying derivative contracts.

        Income Tax Expense (Benefit).    We incurred losses before income taxes in 2008 and 2009. These losses were a key consideration that led us to provide a valuation allowance against our net deferred tax assets at December 31, 2009 and June 30, 2010 since we could not conclude that it is more likely

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than not that the net deferred tax assets will be fully realized. As long as we continue to conclude that we have a need for a full valuation allowance against our net deferred tax assets, we likely will not have any income tax expense or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims, or for state income taxes. The income tax expense we recorded for the six months ended June 30, 2009 primarily relates to federal AMT resulting from the sale of the Hastings Complex in February 2009. The income tax benefit we recorded for the six months ended June 30, 2010 relates to an increase in the estimated net operating loss carryback claim for the 2003 through 2005 tax years.

        Net Income (Loss).    Net income for the first half of 2010 was $47.7 million compared to net loss of $34.3 million for the same period in 2009. The change between periods is the result of the items discussed above.

Liquidity and Capital Resources

        Our primary sources of liquidity are cash generated from our operations and amounts available under our revolving credit facility.

Cash Flows

 
  Six Months Ended
June 30,
 
 
  2009   2010  
 
  (in thousands)
 

Cash provided by operating activities

  $ 47,260   $ 55,108  

Cash (used in) provided by investing activities

    60,686     5,174  

Cash (used in) provided by financing activities

    (106,553 )   (58,497 )

        Net cash provided by operating activities was $55.1 million in the first six months of 2010 compared with $47.3 million in the first six months of 2009. Cash flows from operating activities in the first six months of 2010 as compared to the first six months of 2009 were favorably impacted by increases in commodity prices partially offset by decreased production.

        Net cash provided by investing activities was $5.2 million in the first six months of 2010 and $60.7 million in the first six months of 2009. The primary investing activities in the first six months of 2010 were the receipt of $99.4 million in net cash proceeds from the sales of our Texas producing properties in the second quarter of 2010, offset by $90.7 million in capital expenditures on oil and natural gas properties related to our capital expenditure program. The primary investing activities in the first six months of 2009 were the receipt of $200.1 million in cash proceeds from the sale of the Hastings Complex offset by $116.7 million in capital expenditures on oil and natural gas properties related to our 2009 capital expenditure program and $21.3 million paid to acquire certain Sacramento Basin assets.

        Net cash used in financing activities was $58.5 million in the first six months of 2010 compared to $106.6 million during the first six months of 2009. The primary financing activities in the first six months of 2010 were $31.9 million in net payments made on our revolving credit facility and $30.7 million of principal repayments on the second lien term loan, both of which were primarily funded by proceeds from the sales of our producing properties in Texas. The primary financing activities in the first six months of 2009 were $84.7 million in net payments made on our revolving credit facility and $5.5 million of principal payments on the second lien term loan, both of which were primarily funded by proceeds from the Hastings Complex sale. Additionally, we paid approximately $15.3 million in May 2009 to settle financed derivative premiums.

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Capital Resources and Requirements

        We plan to make substantial capital expenditures in the future for the acquisition, exploration, exploitation and development of oil and natural gas properties. We expect that our exploration, exploitation and development capital expenditures, which were $96.2 million in the first six months of 2010, will be approximately $220 million in 2010. We expect to fund our 2010 capital expenditure budget primarily with cash flow from operations, supplemented with borrowings under our revolving credit facility and the proceeds from the sale of our Texas producing assets and capital raising transactions that may include joint venture transactions and/or an issuance of equity. In a series of transactions that occurred during the second quarter of 2010, we completed the divesture of our Texas producing properties. The proceeds from the sales were used to reduce the principal balances of our revolving credit facility and second lien term loan by approximately $66.9 million and $30.7 million, respectively. Additional uncertainties relating to our capital resources and requirements in 2010 include the possibility that one or more of the counterparties to our hedging arrangements may fail to perform under the contracts, the effects of changes in commodity prices and differentials and the possibility that we will pursue one or more significant acquisitions that would require additional debt or equity financing.

        Amended Revolving Credit Facility.    In December 2009, we entered into the third amended and restated credit agreement governing our revolving credit facility, which now has a maturity date of January 15, 2013. The agreement contains customary representations, warranties, events of default, indemnities and covenants, including covenants that restrict our ability to incur indebtedness, require us to maintain derivative contracts covering a portion of our anticipated production and require us to maintain specified ratios of current assets to current liabilities and debt to EBITDA. The minimum ratio of current assets to current liabilities (as those terms are defined in the agreement) is one to one; the maximum ratio of debt to EBITDA (as defined in the agreement) is four to one. While we do not expect to be in violation of any of our debt covenants during 2010, we believe that it will be important to monitor the debt to EBITDA ratio requirement, especially if our EBITDA is less than we expect due to operational problems or other factors, or if our borrowing needs are greater than we expect. The agreement requires us to reduce amounts outstanding under the facility with the proceeds of certain transactions or events, including sales of assets, in certain circumstances. The revolving credit facility is secured by a first priority lien on substantially all of our assets.

        Loans under the revolving credit facility designated as "Base Rate Loans" bear interest at a floating rate equal to (i) the greater of (x) Bank of Montreal's announced base rate, (y) the overnight federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.5%, plus (ii) an applicable margin ranging from 0.75% to 1.50%, based upon utilization. Loans designated as "LIBO Rate Loans" under the revolving credit facility bear interest at (i) LIBOR plus (ii) an applicable margin ranging from 2.25% to 3.00%, based upon utilization. A commitment fee of 0.5% per annum is payable with respect to unused borrowing availability under the facility.

        The revolving credit facility has a total capacity of $300.0 million, but is limited by a borrowing base which was re-affirmed by the lenders in May 2010 at $125.0 million. The borrowing base is subject to redetermination twice each year, and may be redetermined at other times at our request or at the request of the lenders. Lending commitments under the facility have been allocated at various percentages to a syndicate of ten banks. Certain of the institutions included in the syndicate have received support from governmental agencies in connection with events in the credit markets. A failure of any members of the syndicate to fund under the facility, or a reduction in the borrowing base, would adversely affect our liquidity. As of July 30, 2010, we have $31.0 million outstanding under the facility and $89.9 million in available borrowing capacity. We paid $66.9 million toward the principal balance of our revolving credit facility during the second quarter of 2010 with the proceeds from the sales of our Texas producing properties.

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        Second Lien Term Loan.    We entered into a $500.0 million senior secured second lien term loan agreement in May 2007. The term loan agreement contains customary representations, warranties, events of default and indemnities and certain customary operational covenants, including covenants that restrict our ability to incur additional indebtedness. The agreement requires us to maintain derivative contracts covering at least 50% of our projected oil and natural gas production on an annual basis until the maturity date of the term loan. We cannot, however, enter into derivative contracts (other than certain put contracts) covering more than 80% of such projected oil and gas production in any month. The agreement also prohibits us from paying dividends on our common stock. The agreement will require us to make offers to prepay amounts outstanding under the second lien term loan facility with the proceeds of certain transactions or events, including sales of assets, in certain circumstances. Amounts prepaid under the facility may not be reborrowed. The term loan facility is secured by a second priority lien on substantially all of our assets. We repaid $30.7 million of principal under the facility in the second quarter of 2010 after the sales of our Texas producing properties and $5.5 million of principal in February 2009 after the Hastings Complex sale. The maturity date of the principal on the second lien term loan is May 8, 2014.

        Loans under the second lien term loan facility designated as "Base Rate Loans" bear interest at a floating rate equal to (i) the greater of the overnight federal funds rate plus 0.50% and the administrative agent's announced base rate, plus (ii) 3.00%. Loans designated as "LIBO Rate Loans" bear interest at LIBOR plus 4.00%.

        Senior Notes.    In October 2009, we issued $150.0 million of 11.50% senior unsecured notes due in October 2017 at a price of 95.03% of par. The senior notes pay interest semi-annually in arrears on April 1 and October 1 of each year. We may redeem the senior notes prior to October 1, 2013 at a "make-whole price" defined in the indenture. Beginning October 1, 2013, we may redeem the notes at a redemption price equal to 105.75% of the principal amount and declining to 100% by October 1, 2016. The indenture governing the notes contains operational covenants that, among other things, limit our ability to make investments, incur additional indebtedness or create liens on our assets.

        Because we must dedicate a substantial portion of our cash flow from operations to the payment of amounts due under our debt agreements, that portion of our cash flow is not available for other purposes. Our ability to make scheduled interest payments on our indebtedness and pursue our capital expenditure plan will depend to a significant extent on our financial and operating performance, which is subject to prevailing economic conditions, commodity prices and a variety of other factors. If our cash flow and other capital resources are insufficient to fund our debt service obligations and our capital expenditure budget, we may be forced to reduce or delay scheduled capital projects, sell material assets or operations and/or seek additional capital. Needed capital may not be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness and certain other means is limited by covenants in our debt agreements. In addition, pursuant to mandatory prepayment provisions in our credit facilities, our ability to respond to a shortfall in our expected liquidity by selling assets or incurring additional indebtedness would be limited by provisions in the facilities that require us to use some or all of the proceeds of such transactions to reduce amounts outstanding under one or both of the facilities in some circumstances. If we are unable to obtain funds when needed and on acceptable terms, we may not be able to complete acquisitions that may be favorable to us, meet our debt obligations or finance the capital expenditures necessary to replace our reserves.

Off-Balance Sheet Arrangements

        At June 30, 2010, we had no existing off-balance sheet arrangements, as defined under SEC rules, that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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Item 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        This section provides information about derivative financial instruments we use to manage commodity price volatility. Due to the historical volatility of crude oil and natural gas prices, we have implemented a hedging strategy aimed at reducing the variability of the prices we receive for our production and providing a minimum revenue stream. Currently, we purchase puts and enter into other derivative transactions such as collars and fixed price swaps in order to hedge our exposure to changes in commodity prices. All contracts are settled with cash and do not require the delivery of a physical quantity to satisfy settlement. While this hedging strategy may result in us having lower revenues than we would have if we were unhedged in times of higher oil and natural gas prices, management believes that the stabilization of prices and protection afforded us by providing a revenue floor on a portion of our production is beneficial. We may, from time to time, opportunistically restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts or realize the current value of our existing positions and use the proceeds from such transactions to secure additional contracts for periods in which we believe there is additional unmitigated commodity price risk.

        This section also provides information about derivative financial instruments we use to manage interest rate risk. See "—Interest Rate Derivative Transactions."

Commodity Derivative Transactions

        Commodity Derivative Agreements.    As of June 30, 2010, we had entered into swap, collar and option agreements related to our oil and natural gas production. The aggregate economic effects of those agreements are summarized below. Location and quality differentials attributable to our properties are not included in the following prices. The agreements provide for monthly settlement based on the differential between the agreement price and the actual NYMEX WTI (oil) or NYMEX Henry Hub (natural gas) price.

 
  Oil (NYMEX WTI)   Natural Gas
(NYMEX Henry Hub)
 
 
  Barrels/day   Weighted Avg.
Prices per Bbl
  MMBtu/day   Weighted Avg.
Prices per MMBtu
 

July 1 - December 31, 2010:

                         
 

Swaps

    1,000   $ 66.75       $  
 

Swap arrangements(1)

      $     11,000   $ 7.00  
 

Collars(1)

    5,150   $ 60.00/$86.53     6,900   $ 7.50/$7.00  
 

Collar arrangements(1)(2)

      $     10,000   $ 6.00/$7.00  
 

Puts

    1,850   $ 40.00     31,000   $ 6.00  

January 1 - December 31, 2011:

                         
 

Collars(1)

    5,000   $ 50.00/$140.40     12,000   $ 5.75/$7.12  
 

Puts(1)

    2,000   $ 50.00     48,000   $ 6.31  

January 1 - December 31, 2012:

                         
 

Collars(1)

    3,000   $ 60.00/$121.10       $  
 

Puts(1)

      $     37,300   $ 5.81  

(1)
Reflects the impact of call spreads and purchased calls, which are transactions we entered into for the purpose of modifying or eliminating the ceiling (or call) portion of certain collar arrangements.

(2)
Reflects separate put and sold call contracts, resulting in a collar arrangement.

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Table of Contents

        We also use natural gas basis swaps to fix the differential between the NYMEX Henry Hub price and the PG&E Citygate price, the index on which the majority of our natural gas is sold. Our natural gas basis swaps as of June 30, 2010 are presented below:

 
  Floating Index   MMBtu/Day   Weighted
Avg. Basis
Differential to
NYMEX HH
(per MMBtu)
 

Basis Swaps:

               
 

July 1 - December 31, 2010

  PG&E Citygate   51,618   $ 0.14  
 

January 1 - December 31, 2011

  PG&E Citygate   57,224   $ 0.11  
 

January 1 - December 31, 2012

  PG&E Citygate   47,400   $ 0.28  

Portfolio of Derivative Transactions

        Our portfolio of commodity derivative transactions as of June 30, 2010 is summarized below:


Oil

Type of Contract
  Counterparty   Basis   Quantity
(Bbl/d)
  Strike Price
($/Bbl)
  Term

Swap

  Fortis Bank   NYMEX     1,000   $ 66.75   Jul 1 - Dec 31, 10

Collar

  Bank of Oklahoma   NYMEX     3,500   $ 60.00/$73.00   Jul 1 - Dec 31, 10

Collar

  Fortis Bank   NYMEX     1,000   $ 60.00/$72.80   Jul 1 - Dec 31, 10

Collar

  Bank of Montreal   NYMEX     650   $ 60.00/$81.75   Jul 1 - Dec 31, 10

Call Spread

  Scotia Capital   NYMEX     1,000   $ 72.80/$95.00   Jul 1 - Dec 31