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Venoco 10-Q 2011

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 September 30, 2011

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 ý    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 September 30, 2011, there were 61,607,796 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, anticipated pricing under sales contracts, amounts of future capital expenditures, our future debt levels and liquidity, our future compliance with covenants under our revolving credit facility and our construction of the new pipeline at 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, 2010. 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, 2010 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 onshore 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;

    the consequences of changes we may make from time to time to our capital expenditure budget, including the impact of those changes on our production levels, reserves, results of operations and liquidity;

    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 potential unavailability of drilling rigs and other field equipment and services;

    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;

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    the effect of any business combination, joint venture or other significant transaction we may pursue, or the costs of litigation related thereto;

    potential delays in completing our onshore South Ellwood pipeline and our potential inability to enter into sales agreements for South Ellwood production on terms we expect;

    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 in the Gulf of Mexico, from the Dodd-Frank Wall Street Reform and Consumer Protection Act or its implementing regulations and from regulations relating to greenhouse gas emissions;

    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;

    natural disasters, including severe weather;

    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 September 30, 2011

TABLE OF CONTENTS

PART I.

 

FINANCIAL INFORMATION

  2

Item 1.

 

Financial Statements (Unaudited)

   

 

Condensed Consolidated Balance Sheets at December 31, 2010 and September 30, 2011

  2

 

Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2010 and the Three and Nine Months Ended September 30, 2011

  3

 

Condensed Consolidated Statements of Changes in Stockholders' Equity for the Nine Months Ended September 30, 2011

  4

 

Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and the Nine Months Ended September 30, 2011

  5

 

Notes to Condensed Consolidated Financial Statements

  6

Item 2.

 

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

  30

Item 3.

 

Quantitative and Qualitative Disclosures about Market Risk

  44

Item 4.

 

Controls and Procedures

  48

PART II.

 

OTHER INFORMATION

  49

Item 1.

 

Legal Proceedings

  49

Item 1A.

 

Risk Factors

  49

Item 2.

 

Unregistered Sales of Equity Securities and Use of Proceeds

  49

Item 3.

 

Defaults upon Senior Securities

  49

Item 4.

 

Removed and Reserved

  50

Item 5.

 

Other Information

  50

Item 6.

 

Exhibits

  50

Signatures

  51

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,
2010
  September 30,
2011
 

ASSETS

             

CURRENT ASSETS:

             
 

Cash and cash equivalents

  $ 5,024   $ 9  
 

Accounts receivable

    29,602     31,715  
 

Inventories

    6,229     6,494  
 

Other current assets

    4,585     5,036  
 

Income taxes receivable

    931      
 

Commodity derivatives

    26,407     50,870  
           
   

Total current assets

    72,778     94,124  
           

PROPERTY, PLANT AND EQUIPMENT, AT COST:

             
 

Oil and gas properties, full cost method of accounting

             
   

Proved

    1,734,190     1,900,742  
   

Unproved

    42,686     51,611  
   

Accumulated depletion

    (1,147,688 )   (1,208,264 )
           
     

Net oil and gas properties

    629,188     744,089  
 

Other property and equipment, net of accumulated depreciation and amortization of $16,588 and $18,190 at December 31, 2010 and September 30, 2011, respectively

    18,856     16,641  
           
     

Net property, plant and equipment

    648,044     760,730  
           

OTHER ASSETS:

             
 

Commodity derivatives

    21,462     30,426  
 

Deferred loan costs

    6,096     15,755  
 

Other

    2,543     2,339  
           
   

Total other assets

    30,101     48,520  
           

TOTAL ASSETS

  $ 750,923   $ 903,374  
           

LIABILITIES AND STOCKHOLDERS' EQUITY

             

CURRENT LIABILITIES:

             
 

Accounts payable and accrued liabilities

  $ 45,396   $ 49,553  
 

Interest payable

    5,538     6,085  
 

Commodity and interest derivatives

    33,483     25,449  
           
   

Total current liabilities

    84,417     81,087  
           

LONG-TERM DEBT

    633,592     681,781  

COMMODITY AND INTEREST DERIVATIVES

    23,430     14,171  

ASSET RETIREMENT OBLIGATIONS

    93,721     86,561  
           
   

Total liabilities

    835,160     863,600  
           

COMMITMENTS AND CONTINGENCIES

             

STOCKHOLDERS' EQUITY:

             
 

Common stock, $.01 par value (200,000,000 shares authorized; 56,241,672 and 61,607,796 shares issued and outstanding at December 31, 2010 and September 30, 2011, respectively)

    562     616  
 

Additional paid-in capital

    348,573     440,638  
 

Retained earnings (accumulated deficit)

    (433,372 )   (401,480 )
           
   

Total stockholders' equity

    (84,237 )   39,774  
           

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

  $ 750,923   $ 903,374  
           

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
September 30,
  Nine Months Ended
September 30,
 
 
  2010   2011   2010   2011  

REVENUES:

                         
 

Oil and natural gas sales

  $ 68,905   $ 77,296   $ 219,333   $ 241,533  
 

Other

    1,507     1,635     3,893     3,877  
                   
   

Total revenues

    70,412     78,931     223,226     245,410  

EXPENSES:

                         
 

Lease operating expense

    20,707     28,684     64,152     71,360  
 

Property and production taxes

    1,742     1,796     5,314     4,783  
 

Transportation expense

    2,750     2,367     6,489     7,023  
 

Depletion, depreciation and amortization

    19,475     20,406     58,191     63,810  
 

Accretion of asset retirement obligations

    1,518     1,623     4,649     4,821  
 

General and administrative, net of amounts capitalized

    8,264     9,236     28,435     27,889  
                   
   

Total expenses

    54,456     64,112     167,230     179,686  
                   
   

Income (loss) from operations

    15,956     14,819     55,996     65,724  

FINANCING COSTS AND OTHER:

                         
 

Interest expense, net

    10,117     16,005     30,539     44,678  
 

Amortization of deferred loan costs

    499     592     1,855     1,715  
 

Interest rate derivative losses (gains), net

    11,048         36,848     1,083  
 

Loss on extinguishment of debt

                1,357  
 

Commodity derivative losses (gains), net

    (20,896 )   (38,572 )   (75,931 )   (15,001 )
                   
   

Total financing costs and other

    768     (21,975 )   (6,689 )   33,832  
                   
   

Income (loss) before income taxes

    15,188     36,794     62,685     31,892  

Income tax provision (benefit)

    (200 )       (400 )    
                   
   

Net income (loss)

  $ 15,388   $ 36,794   $ 63,085   $ 31,892  
                   

Earnings per common share:

                         
 

Basic

  $ 0.28   $ 0.60   $ 1.16   $ 0.53  
 

Diluted

  $ 0.28   $ 0.60   $ 1.14   $ 0.52  

Weighted average common shares outstanding:

                         
 

Basic

    52,410     58,738     51,844     57,881  
 

Diluted

    53,259     58,830     52,750     58,038  

See notes to condensed consolidated financial statements.

3


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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, 2010

    56,242   $ 562   $ 348,573   $ (433,372 ) $ (84,237 )
 

Issuance of stock for cash upon exercise of options

    186     2     1,654         1,656  
 

Issuance of restricted shares, net of cancellations

    562     6     (6 )        
 

Share-based compensation

            8,030         8,030  
 

Issuance of common stock pursuant to Employee Stock Purchase Plan

    18         262         262  
 

Issuance of stock, net of underwriters discounts

    4,600     46     82,754         82,800  
 

Stock issuance costs

            (629 )       (629 )
 

Net income (loss)

                31,892     31,892  
                       

BALANCE AT SEPTEMBER 30, 2011

    61,608   $ 616   $ 440,638   $ (401,480 ) $ 39,774  
                       

See notes to condensed consolidated financial statements.

4


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VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In thousands)

 
  Nine Months Ended
September 30,
 
 
  2010   2011  

CASH FLOWS FROM OPERATING ACTIVITIES:

             
 

Net income (loss)

  $ 63,085   $ 31,892  
 

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

             
   

Depletion, depreciation and amortization

    58,191     63,810  
   

Accretion of asset retirement obligations

    4,649     4,821  
   

Deferred income tax provision (benefit)

    8,400      
   

Share-based compensation

    4,118     4,966  
   

Amortization of deferred loan costs

    1,855     1,715  
   

Amortization of bond discounts and other non-cash interest

    441     500  
   

Loss on extinguishment of debt

        1,357  
   

Unrealized interest rate swap derivative losses (gains)

    23,285     (40,064 )
   

Unrealized commodity derivative losses (gains) and amortization of premiums

    (52,062 )   (3,455 )
 

Changes in operating assets and liabilities:

             
   

Accounts receivable

    6,393     (2,113 )
   

Inventories

    (105 )   (265 )
   

Other current assets

    (1,776 )   (589 )
   

Income taxes receivable

    (8,918 )   931  
   

Other assets

    26     204  
   

Accounts payable and accrued liabilities

    (4,912 )   10,059  
 

Net premiums paid on derivative contracts

    (6,711 )   (7,201 )
           
     

Net cash provided by operating activities

    95,959     66,568  

CASH FLOWS FROM INVESTING ACTIVITIES:

             
 

Expenditures for oil and natural gas properties

    (152,353 )   (189,467 )
 

Acquisitions of oil and natural gas properties

    (2,645 )   (213 )
 

Expenditures for other property and equipment

    (2,331 )   (1,088 )
 

Proceeds from sale of oil and natural gas properties

    98,103      
           
   

Net cash (used in) provided by investing activities

    (59,226 )   (190,768 )

CASH FLOWS FROM FINANCING ACTIVITIES:

             
 

Proceeds from long-term debt

    105,000     563,000  
 

Principal payments on long-term debt

    (152,570 )   (515,311 )
 

Payments for deferred loan costs

    (281 )   (12,548 )
 

Proceeds from issuance of common stock

        82,800  
 

Stock issuance costs

        (629 )
 

Proceeds from stock incentive plans and other

    10,709     1,873  
           
   

Net cash (used in) provided by financing activities

    (37,142 )   119,185  
           
     

Net increase (decrease) in cash and cash equivalents

    (409 )   (5,015 )
 

Cash and cash equivalents, beginning of period

    419     5,024  
           
     

Cash and cash equivalents, end of period

  $ 10   $ 9  
           

Supplemental Disclosure of Cash Flow Information—

             
 

Cash paid for interest

  $ 25,583   $ 43,641  
 

Cash paid (refunded) for income taxes

  $ 250   $ (931 )

Supplemental Disclosure of Noncash Activities—

             
 

Accrued capital expenditures at period end

  $ 18,325   $ 15,017  
 

Increase (decrease) in accrued capital expenditures

  $ 3,090   $ (5,355 )

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, 2010 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 in which the specific transaction occurs.

        The Company incurred losses before income taxes in 2008 and 2009. These losses and expected future taxable losses were key considerations that led the Company to provide a valuation allowance against its net deferred tax assets at December 31, 2010 and September 30, 2011 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. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings; consistent and sustained pre-tax earnings; sustained or continued improvements in oil and natural gas commodity prices; consistent, meaningful production and proved

6


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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)


reserves from the Company's onshore Monterey shale project; and meaningful production and proved reserves from the CO2 flood at the Hastings field. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods.

        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 benefit for the nine months ended September 30, 2010 relates to an increase in the estimated net operating loss carryback claim for the 2003 through 2005 tax years. Due to the valuation allowance, no income tax expense or benefit was recorded for the nine months ended September 30, 2011.

        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
September 30,
  Nine Months
Ended
September 30,
 
 
  2010   2011   2010   2011  

Dilutive

    4,843     3,187     4,884     3,200  

Anti-dilutive

    148     593     511     559  

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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
September 30,
  Nine Months
Ended
September 30,
 
 
  2010   2011   2010   2011  

Net income (loss)

  $ 15,388   $ 36,794   $ 63,085   $ 31,892  

Allocation of net income to unvested restricted stock

    (746 )   (1,718 )   (2,982 )   (1,492 )
                   
 

Net income (loss) allocated to common stock

  $ 14,642   $ 35,076   $ 60,103   $ 30,400  
                   

Basic weighted average common shares outstanding

    52,410     58,738     51,844     57,881  
 

Add: dilutive effect of stock options

    849     92     906     157  
                   

Diluted weighted average common shares outstanding

    53,259     58,830     52,750     58,038  
                   

Basic earnings per common share

  $ 0.28   $ 0.60   $ 1.16   $ 0.53  

Diluted earnings per common share

  $ 0.28   $ 0.60   $ 1.14   $ 0.52  

        Related Party Transactions—The Company has entered into a non-exclusive aircraft sublease agreement with TimBer, LLC, a company owned by the Company's Chief Executive Officer and his wife. Through September 30, 2011, the Company has incurred approximately $1.1 million of sublease charges related to the agreement, all of which is recorded in accounts payable and accrued liabilities on the Company's balance sheet at September 30, 2011.

        Recent Events—On August 26, 2011, the Company's board of directors received a proposal from its chairman and chief executive officer, Timothy Marquez, to acquire all of the outstanding shares of common stock of Venoco of which he is not the beneficial owner for $12.50 per share in cash. Mr. Marquez is the beneficial owner of approximately 50.3% of Venoco's common stock. According to the proposal letter, Mr. Marquez will form an acquisition vehicle for the purpose of completing the acquisition. The proposal is subject to, among other things, Mr. Marquez being able to secure financing with acceptable terms. The Company's board of directors has formed a special committee comprised of all independent directors to evaluate and consider this proposal as well as third party alternatives. As of October 31, 2011, no decisions have been made by the special committee with respect to the Company's response to the proposal.

        Reclassifications—The Company made certain reclassifications to its prior consolidated statements of operations to be consistent with the current presentation. The consolidated statements of operations were modified to reclassify oil gravity adjustments paid to other oil pipeline participants from transportation expense to oil and natural gas sales to more appropriately present the impact of oil gravity on the price received rather than as a component of transportation. These reclassifications had no impact on the Company's financial position, income (loss) before taxes or cash flows from operating, investing or financing activities.

        Recently Issued Accounting Standards—In May 2011, the FASB issued Accounting Standards Update No. 2011-04—Fair Value Measurement—Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs, which is effective for interim and annual periods

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)


beginning after December 15, 2011. The ASU is not expected to have a significant impact on the Company's financial statements, other than additional disclosures.

2. ACQUISITIONS AND SALES OF PROPERTIES

        Sale of Cat Canyon Field.    In December 2010, the Company sold its interests in the Cat Canyon field in Southern California for $8.7 million (after closing adjustments). The Company applied the proceeds from the sale to repay $8.5 million of the principal balance on the second lien term loan. No gain or loss was recognized on the sale as the Company recorded the net proceeds as a reduction to the capitalized costs of its oil and natural gas properties.

        Sales of Texas Assets.    In the second quarter of 2010, the Company sold its interests in its producing properties in Texas ("Texas Sales") for $98.1 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 recorded the proceeds from the Texas Sales as a reduction to 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.

3. LONG-TERM DEBT

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

 
  December 31,
2010
  September 30,
2011
 

Revolving credit agreement due March 2016

  $ 35,000   $ 38,000  

Second lien term loan due May 2014

    455,311      

11.50% senior notes due October 2017

    143,281     143,781  

8.875% senior notes due February 2019

        500,000  
           
 

Total long-term debt

    633,592     681,781  

Less: current portion of long-term debt

         
           
 

Long-term debt, net of current portion

  $ 633,592   $ 681,781  
           

        Revolving credit facility.    In April 2011, the Company entered into a fourth amended and restated credit agreement which increased the size of its revolving credit facility from $300 million to $500 million. The facility has a maturity date of March 31, 2016. The borrowing base (currently established at $200 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 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

3. LONG-TERM DEBT (Continued)


the facility. Loans made under the revolving credit facility are designated, at the Company's option, as either "Base Rate Loans" or "LIBO Rate Loans." 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, (y) the overnight federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.0%, plus (ii) an applicable margin ranging from 0.75% to 1.75%, based on utilization. Loans designated as LIBO Rate Loans under the facility bear interest at (i) LIBOR plus (ii) an applicable margin ranging from 1.75% to 2.75%, 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 11 banks. Certain of the institutions included in the syndicate have received support from governmental agencies in connection with events in the credit markets.

        In February 2011, the Company repaid the outstanding balance of the revolving credit facility with proceeds from an issuance of common stock (see note 7). As of October 31, 2011, the Company had $43.0 million outstanding on the facility and had available borrowing capacity of $153.2 million under the facility, net of the outstanding balance of $43.0 million and $3.8 million in outstanding letters of credit.

        Second lien term loan facility and 8.875% senior notes.    In May 2007, the Company entered into a $500.0 million senior secured second lien term loan facility (the "second lien term loan facility"), which was due to mature on May 8, 2014. Prior to repayment of the second lien term loan facility in February 2011 (see below), loans made under the second lien term loan facility were designated, at the Company's option, as either "Base Rate Loans" or "LIBO Rate Loans." Loans designated as Base Rate Loans bore 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 bore interest at LIBOR plus 4.00%.

        In February 2011, the Company issued $500 million in 8.875% senior notes due in February 2019 at par. Concurrently with the sale of the 8.875% senior notes, the Company repaid in full the outstanding principal balance of $455.3 million on the second lien term loan, plus accrued interest of $1.6 million. The 8.875% senior notes pay interest semi-annually in arrears on February 15 and August 15 of each year. The Company may redeem the notes prior to February 15, 2015 at a "make whole premium" defined in the indenture. Beginning February 15, 2015, the Company may redeem the notes at a redemption price of 104.438% of the principal amount and declining to 100% by February 15, 2017. The 8.875% senior notes are senior unsecured obligations and contain operational covenants that, among other things, limit the Company's ability to make investments, incur additional indebtedness, issue preferred stock, pay dividends, repurchase its stock, create liens or sell assets.

        The Company recorded a loss on extinguishment of debt of $1.4 million in connection with the repayment of the second lien term loan.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

3. LONG-TERM DEBT (Continued)

        11.50% 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 senior notes pay interest semi-annually in arrears on April 1 and October 1 of each year. The Company may 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 11.50% 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 Company was in compliance with all debt covenants at September 30, 2011.

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. The Company may use the proceeds from such transactions to secure additional contracts for periods in which the Company believes it has additional unmitigated commodity price risk or for other corporate purposes.

        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.

        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.

        The Company has paid premiums related to certain of its outstanding derivative contracts. These premiums are amortized into commodity derivative (gains) losses over the period for which the

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)


contracts are effective. At September 30, 2011, the balance of unamortized net derivative premiums paid was $16.5 million, of which $2.0 million, $11.4 million and $3.1 million will be amortized in the remainder of 2011 and in 2012 and 2013, respectively.

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

 
  Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
 
  2010   2011   2010   2011  

Realized commodity derivative (gains) losses

  $ (10,863 ) $ (2,571 ) $ (23,869 ) $ (11,546 )

Amortization of commodity derivative premiums

    5,657     1,990     16,972     5,970  

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

    (15,690 )   (37,991 )   (69,034 )   (9,425 )
                   
 

Commodity derivative (gains) losses

  $ (20,896 ) $ (38,572 ) $ (75,931 ) $ (15,001 )
                   

        As of September 30, 2011, the Company had entered into various 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)
 
 
  Weighted Avg.
Barrels/day
  Weighted Avg.
Prices per Bbl
  Weighted Avg.
MMBtu/day
  Weighted Avg.
Prices per MMBtu
 

October 1 - December 31, 2011:

                         
 

Swaps

    1,000   $ 105.65     24,000   $ 4.44  
 

Collars(1)

    5,000   $ 50.00/$100.00       $  
 

Puts(1)

    2,000   $ 50.00     36,000   $ 5.92  

January 1 - December 31, 2012:

                         
 

Collars(1)

    6,500   $ 80.00/$118.15     13,400   $ 4.50/$5.25  
 

Puts(1)

    2,000   $ 60.00     37,300   $ 5.81  

January 1 - December 31, 2013:

                         
 

Collars

    3,900   $ 81.79/113.59     20,000   $ 4.50/$5.40  
 

Puts

      $     20,000   $ 5.00  

(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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

        The Company has also entered into certain oil and natural gas basis swaps. The oil basis swaps fix the differential between the NYMEX WTI crude price index ("WTI") and the Inter-Continental Exchange Brent crude price index ("Brent"). Historically the two price indexes have demonstrated a close correlation. The Southern California indexes on which the Company sells a significant percentage of its oil have historically demonstrated a close correlation with these two major crude oil benchmarks. Recently, however, the relationship between WTI and Brent has diverged, favoring Brent crude, and the Southern California indexes most relevant to the Company have continued to track their correlation to Brent prices. The oil basis swaps entered into by the Company attempt to fix the premium Southern California indexes are realizing relative to WTI. The natural gas basis swaps fix the differential between the Henry Hub price and the PG&E Citygate price, the index on which the majority of the Company's natural gas is sold. The Company's oil and natural gas basis swaps as of September 30, 2011 are presented below:

 
  Oil Basis Swaps (NYMEX WTI)   Natural Gas Basis Swaps
(NYMEX Henry Hub)
 
 
  Floating
Index
  Weighted Avg.
Bbls/Day
  Weighted
Avg. Basis
Differential to
NYMEX WTI
(per Bbl)
  Floating
Index
  Weighted Avg.
MMBtu/Day
  Weighted
Avg. Basis
Differential to
NYMEX HH
(per MMBtu)
 

Basis Swaps:

                                 
 

October 1 - December 31, 2011

  Brent Crude     3,700   $ 9.30   PG&E Citygate     57,224   $ 0.11  
 

January 1 - December 31, 2012

  Brent Crude     7,630   $ 6.90   PG&E Citygate     47,400   $ 0.28  
 

January 1 - December 31, 2013

  Brent Crude     3,900   $ 5.88         $  

        Interest Rate Swap.    The Company previously entered into interest rate swap transactions to lock in its interest cost on $500.0 million of variable rate borrowings through May 2014. Under the swap arrangements, the Company paid a fixed interest rate of 3.840% and received a floating interest rate based on the one-month LIBO rate, with settlements made monthly. As a result of the interest rate swap agreement, $500 million of the Company's variable rate debt effectively bore interest at a fixed rate of approximately 7.8%. The Company did not designate the interest rate swap as a hedge.

        In February 2011, the Company repaid the principal balance outstanding on the second lien term loan from proceeds received from the issuance of the 8.875% senior notes (see note 3), which reduced the Company's debt subject to variable rate interest to any amounts which may be outstanding under the Company's revolving credit facility. As a result, the Company settled the interest rate swaps for $38.1 million in February 2011.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

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

 
  Three Months
Ended
September 30,
  Nine Months
Ended
September 30,
 
 
  2010   2011   2010   2011  

Realized interest rate derivative (gains) losses

  $ 4,495   $   $ 13,563   $ 41,147  

Unrealized interest rate derivative (gains) losses

    6,553         23,285     (40,064 )
                   
 

Interest rate derivative (gains) losses, net

  $ 11,048   $   $ 36,848   $ 1,083  
                   

        Fair Value of Derivative Instruments.    The estimated fair values of derivatives included in the consolidated balance sheets at December 31, 2010 and September 30, 2011 are summarized below. The net fair value of the Company's derivatives changed by $50.7 million from a net liability of $9.0 million at December 31, 2010 to a net asset of $41.7 million at September 30, 2011, primarily due to (i) settlement of the interest rate swaps in February 2011, (ii) changes in the futures prices for oil and natural gas, which are used in the calculation of the fair value of commodity derivatives, (iii) settlement of commodity derivative positions during the current period and (iv) changes to the Company's commodity derivative portfolio during 2011. 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)


Company has not designated any of its derivative contracts as hedging instruments. The main headings represent the balance sheet captions for the contracts presented.

 
  December 31,
2010
  September 30,
2011
 

Current Assets—Commodity derivatives:

             
 

Oil derivative contracts

  $ 95   $ 20,718  
 

Gas derivative contracts

    26,312     30,152  
           

    26,407     50,870  
           

Other Assets—Commodity derivatives:

             
 

Oil derivative contracts

        17,559  
 

Gas derivative contracts

    21,462     12,867  
           

    21,462     30,426  
           

Current Liabilities—Commodity and interest derivatives:

             
 

Oil derivative contracts

    (8,039 )   (22,339 )
 

Gas derivative contracts

    (6,890 )   (3,110 )
 

Interest rate derivative contracts

    (18,554 )    
           

    (33,483 )   (25,449 )
           

Commodity and interest derivatives:

             
 

Oil derivative contracts

    (1,921 )   (14,171 )
 

Gas derivative contracts

         
 

Interest rate derivative contracts

    (21,509 )    
           

    (23,430 )   (14,171 )
           
   

Net derivative asset (liability)

  $ (9,044 ) $ 41,676  
           

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).

        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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

5. FAIR VALUE MEASUREMENTS (Continued)

            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 September 30, 2011 (in thousands).

 
  Level 1   Level 2   Level 3   Fair Value
as of
September 30,
2011
 

Assets (Liabilities):

                         
 

Commodity derivative contracts

  $   $ 81,296   $   $ 81,296  
 

Commodity derivative contracts

        (39,620 )       (39,620 )

        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 considers 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.

        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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

5. FAIR VALUE MEASUREMENTS (Continued)


available market data. This disclosure does not impact our financial position, results of operations or cash flows (in thousands).

 
  December 31, 2010   September 30, 2011  
 
  Carrying
Value
  Estimated
Fair Value
  Carrying
Amount
  Estimated
Fair Value
 

Revolving credit agreement

  $ 35,000   $ 35,000   $ 38,000   $ 38,000  

Second lien term loan

    455,311     434,253          

11.50% senior notes

    143,281     162,000     143,781     145,500  

8.875% senior notes

            500,000     450,710  

6. ASSET RETIREMENT OBLIGATIONS

        The Company's asset retirement obligations 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.

        The following table summarizes the activities for the Company's asset retirement obligations for the nine months ended September 30, 2010 and 2011 (in thousands):

 
  Nine Months
Ended
September 30,
2010
  Nine Months
Ended
September 30,
2011
 

Asset retirement obligations at beginning of period

  $ 92,985   $ 94,221  

Revisions of estimated liabilities

    710     (15,095 )

Liabilities incurred/acquired

    4,366     3,365  

Liabilities settled

    (1,942 )   (251 )

Disposition of properties

    (5,292 )    

Accretion expense

    4,649     4,821  
           
 

Asset retirement obligations at end of period

    95,476     87,061  

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

    (1,000 )   (500 )
           
   

Long-term asset retirement obligations

  $ 94,476   $ 86,561  
           

        The revisions of $15.1 million for the nine months ended September 30, 2011 primarily relate to updated estimated useful lives of certain of the Company's offshore platforms and support facilities. In particular, reserve lives for the South Ellwood field were extended in connection with the

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

6. ASSET RETIREMENT OBLIGATIONS (Continued)

September 2011 approval of the common carrier pipeline that will transport oil from the field to refiners and replace the use of a barge.

7. CAPITAL STOCK

        The Company has 65.9 million shares of common stock issued or reserved for issuance at September 30, 2011. At September 30, 2011, the Company has 61.6 million common shares issued and outstanding, of which 2.8 million shares are restricted stock granted under the Company's 2005 stock incentive plan. At September 30, 2011, the Company had approximately 0.9 million options outstanding and 2.8 million shares available to be issued pursuant to awards under its stock incentive plans, including the 2008 Employee Stock Purchase Plan.

        During the first quarter of 2011, the Company sold 4.6 million shares of common stock in a public offering at $18.75 per share and received approximately $82.2 million in net proceeds, after underwriting discounts and estimated expenses.

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 September 30, 2011, there are a total of 902,055 options outstanding with a weighted average exercise price of $13.90 ($6.00 to $20.00), all of which have vested. The options typically have a maximum life of 10 years.

        As of September 30, 2011, there were a total of 2,841,409 shares of restricted stock outstanding under the Company's 2005 stock incentive plan, including 1,070,495 shares granted to its CEO. Restricted shares subject to service conditions only generally vest over a four year period, with 25% vesting on each subsequent anniversary of the grant date. 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 1,855,147 shares is also subject to market conditions based on the Company's total shareholder return in comparison to peer group companies and/or an industry index for each calendar year. Shares of restricted stock subject to market conditions which were granted prior to 2011 have a four year period over which vesting may occur. For grants issued in 2011, this period was expanded by three years in which a portion of the available shares could vest. 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 the 496,846 awards with market conditions granted in February 2011 was estimated to be $17.83 per share. The estimated grant date fair values of restricted share awards are recognized as expense over the requisite service periods.

        As of September 30, 2011, there was $19.5 million of total unrecognized compensation cost related to restricted stock, which is expected to be amortized over a weighted average period of 2.8 years. All compensation cost related to stock options has been recognized.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

8. SHARE-BASED PAYMENTS (Continued)

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

 
  Three Months
Ended
September 30,
  Nine Months
Ended
September 30,
 
 
  2010   2011   2010   2011  

General and administrative expense

  $ 1,660   $ 2,430   $ 5,020   $ 7,140  

Oil and natural gas production expense

    290     260     870     890  
                   
 

Total share-based compensation costs

    1,950     2,690     5,890     8,030  

Less: share-based compensation costs capitalized

    (563 )   (1,127 )   (1,772 )   (3,064 )
                   
 

Share-based compensation expensed

  $ 1,387   $ 1,563   $ 4,118   $ 4,966  
                   

        The following summarizes the Company's stock option activity for the nine months ended September 30, 2011:

 
  Options   Weighted
Average
Exercise
Price
 

Outstanding, start of period

    1,093,758   $ 13.07  

Granted

      $  

Exercised

    (185,753 ) $ 9.69  

Cancelled

    (5,950 ) $ 17.00  
             
 

Outstanding, end of period

    902,055   $ 13.90  
             
 

Exercisable, end of period

    902,055   $ 13.90  

        The following summarizes the Company's unvested restricted stock award activity for the nine months ended September 30, 2011:

 
  Shares   Weighted
Average
Grant Date
Fair Value
 

Non-vested, start of period

    2,603,250   $ 9.70  

Granted

    762,831   $ 17.40  

Vested

    (323,356 ) $ 10.83  

Forfeited

    (201,316 ) $ 12.57  
             
 

Non-vested, end of period

    2,841,409   $ 11.44  
             

        The Company also provides a non-compensatory Employee Stock Purchase Plan (the "ESPP"), for which 1.4 million authorized shares of common stock remain available for issuance. 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

8. SHARE-BASED PAYMENTS (Continued)


by the fair market value of the 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.

9. CONTINGENCIES

        Marquez Proposal—On August 26, 2011 Timothy Marquez, the chairman and chief executive officer of the Company, submitted a nonbinding proposal to the board of directors of the Company to acquire all of the shares of the Company he does not beneficially own for $12.50 per share in cash (the "Marquez Proposal"). In August and September of 2011, four lawsuits were filed in the Delaware Court of Chancery against the Company and each of its directors by shareholders alleging that the Company and directors had breached their fiduciary duties to the shareholders in connection with the Marquez Proposal. A fifth lawsuit was filed in September 2011, also in the Delaware Court of Chancery, naming only Mr. Marquez as a defendant. Each action seeks certification as a class action. In the complaints, the plaintiffs challenge the Marquez Proposal and allege, among other things, that the consideration to be paid pursuant to such proposal is inadequate. The complaints seek, among other relief, to enjoin defendants from consummating the Marquez Proposal and to direct defendants to exercise their fiduciary duties to obtain a transaction that is in the best interests of the shareholders. The Company has reviewed the allegations contained in the complaints and believes they are without merit. The Company intends to defend the litigation vigorously. As such, based on the information known to date, the Company does not believe that it is probable that a material judgment against the Company will result. Therefore, no liability has been accrued.

        Beverly Hills Litigation—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 2012. The Company vigorously defended the actions, and will continue to do so until they are resolved. Certain defendants have made claims for indemnity 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 is currently paying for the defense of these lawsuits under a reservation of its rights. If the insurer ceases to provide such defense, and the Company is unsuccessful

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

9. CONTINGENCIES (Continued)


in enforcing its rights in any subsequent litigation, the Company will 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 expenses, damages or settlement costs ultimately incurred in the lawsuits.

        Based on the information known to us to date, we do not believe that it is probable that a material judgment against us will result. Therefore, no liability has been accrued. 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.

        State Lands Commission Royalty Audit—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 indicated that the Company underpaid royalties due on oil and gas production from the Leases by approximately $5.8 million. In March 2011 the SLC notified the Company that for the period 1997 through 2009 the total underpaid royalties from the Leases were approximately $5.9 million. Based on the Company's 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 periods and may be owed a refund of such overpayments. The Company believes the position of the SLC is without merit and intends to vigorously contest the audit findings and to enforce its rights for refunds of royalties it may have overpaid. We do not believe that it is probable that a material judgment against us will result. Therefore, no liability has been accrued.

        Other—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.

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% and 8.875% 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 September 30, 2011. 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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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS
AT DECEMBER 31, 2010 (Unaudited)
(in thousands)

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

ASSETS

                               

CURRENT ASSETS:

                               
 

Cash and cash equivalents

  $ 5,024   $   $   $   $ 5,024  
 

Accounts receivable

    29,082     121     399         29,602  
 

Inventories

    6,229                 6,229  
 

Other current assets

    4,585                 4,585  
 

Income taxes receivable

    931                 931  
 

Commodity derivatives

    26,407                 26,407  
                       

TOTAL CURRENT ASSETS

    72,258     121     399         72,778  
                       
 

PROPERTY, PLANT & EQUIPMENT, NET

    825,844     (183,940 )   6,140         648,044  
 

COMMODITY DERIVATIVES

    21,462                 21,462  
 

INVESTMENTS IN AFFILIATES

    520,958             (520,958 )    
 

OTHER

    8,578     61             8,639  
                       

TOTAL ASSETS

  $ 1,449,100   $ (183,758 ) $ 6,539   $ (520,958 ) $ 750,923  
                       

LIABILITIES AND STOCKHOLDERS' EQUITY

                               

CURRENT LIABILITIES:

                               
 

Accounts payable and accrued liabilities

  $ 45,346   $ 50   $   $   $ 45,396  
 

Interest payable

    5,538                 5,538  
 

Commodity and interest derivatives

    33,483                 33,483  
                       

TOTAL CURRENT LIABILITIES:

    84,367     50             84,417  
                       

LONG-TERM DEBT

    633,592                 633,592  

COMMODITY AND INTEREST DERIVATIVES

    23,430                 23,430  

ASSET RETIREMENT OBLIGATIONS

    91,127     1,604     990         93,721  

INTERCOMPANY PAYABLES (RECEIVABLES)

    700,821     (650,346 )   (50,475 )        
                       

TOTAL LIABILITIES

    1,533,337     (648,692 )   (49,485 )       835,160  
                       

TOTAL STOCKHOLDERS' EQUITY

    (84,237 )   464,934     56,024     (520,958 )   (84,237 )
                       

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

  $ 1,449,100   $ (183,758 ) $ 6,539   $ (520,958 ) $ 750,923  
                       

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)


CONDENSED CONSOLIDATING BALANCE SHEETS
AT SEPTEMBER 30, 2011 (Unaudited)
(in thousands)

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

ASSETS

                               

CURRENT ASSETS:

                               
 

Cash and cash equivalents

  $ 9   $   $   $   $ 9  
 

Accounts receivable

    31,181     127     407         31,715  
 

Inventories

    6,494                 6,494  
 

Other current assets

    5,036                 5,036  
 

Income tax receivable

                     
 

Commodity derivatives

    50,870                 50,870  
                       

TOTAL CURRENT ASSETS

    93,590     127     407         94,124  
                       
 

PROPERTY, PLANT & EQUIPMENT, NET

    937,278     (184,084 )   7,536         760,730  
 

COMMODITY DERIVATIVES

    30,426                 30,426  
 

INVESTMENTS IN AFFILIATES

    526,633             (526,633 )    
 

OTHER

    18,033     61             18,094  
                       

TOTAL ASSETS

  $ 1,605,960   $ (183,896 ) $ 7,943   $ (526,633 ) $ 903,374  
                       

LIABILITIES AND STOCKHOLDERS' EQUITY

                               

CURRENT LIABILITIES:

                               
 

Accounts payable and accrued liabilities

  $ 49,553   $   $   $   $ 49,553  
 

Interest payable

    6,085                 6,085  
 

Commodity and interest derivatives

    25,449                 25,449  
                       

TOTAL CURRENT LIABILITIES:

    81,087                 81,087  
                       

LONG-TERM DEBT

    681,781                 681,781  

COMMODITY AND INTEREST DERIVATIVES

    14,171                 14,171  

ASSET RETIREMENT OBLIGATIONS

    84,304     1,701     556         86,561  

INTERCOMPANY PAYABLES (RECEIVABLES)

    704,843     (651,876 )   (52,967 )        
                       

TOTAL LIABILITIES

    1,566,186     (650,175 )   (52,411 )       863,600  
                       

TOTAL STOCKHOLDERS' EQUITY

    39,774     466,279     60,354     (526,633 )   39,774  
                       

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

  $ 1,605,960   $ (183,896 ) $ 7,943   $ (526,633 ) $ 903,374  
                       

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

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

REVENUES:

                               
 

Oil and natural gas sales

  $ 69,003   $ (98 ) $   $   $ 68,905  
 

Other

    1,358     64     1,291     (1,206 )   1,507  
                       
   

Total revenues

    70,361     (34 )   1,291     (1,206 )   70,412  
                       

EXPENSES:

                               
 

Lease operating expenses

    20,182         525         20,707  
 

Production and property taxes

    1,670     (11 )   83         1,742  
 

Transportation expense

    3,869     1         (1,120 )   2,750  
 

Depletion, depreciation and amortization

    19,310     28     137         19,475  
 

Accretion of asset retirement obligations

    1,471     30     17         1,518  
 

General and administrative, net of amounts capitalized

    8,191     44     115     (86 )   8,264  
                       
   

Total expenses

    54,693     92     877     (1,206 )   54,456  
                       

Income (loss) from operations

    15,668     (126 )   414         15,956  
                       

FINANCING COSTS AND OTHER:

                               
 

Interest expense, net

    11,088         (971 )       10,117  
 

Amortization of deferred loan costs

    499                 499  
 

Interest rate derivative losses (gains), net

    11,048                 11,048  
 

Commodity derivative losses (gains), net

    (20,896 )               (20,896 )
                       
     

Total financing costs and other

    1,739         (971 )       768  
                       

Equity in subsidiary income

    781             (781 )    
                       

Income (loss) before income taxes

    14,710     (126 )   1,385     (781 )   15,188  

Income tax provision (benefit)

    (678 )   (48 )   526         (200 )
                       

Net income (loss)

  $ 15,388   $ (78 ) $ 859   $ (781 ) $ 15,388  
                       

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)


CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2011 (Unaudited)
(in thousands)

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

REVENUES:

                               
 

Oil and natural gas sales

  $ 76,907   $ 389   $   $   $ 77,296  
 

Other

    1,528     14     1,206     (1,113 )   1,635  
                       
   

Total revenues

    78,435     403     1,206     (1,113 )   78,931  

EXPENSES:

                               
 

Lease operating expenses

    28,172     12     500         28,684  
 

Property and production taxes

    1,919     (190 )   67         1,796  
 

Transportation expense

    3,392             (1,025 )   2,367  
 

Depletion, depreciation and amortization

    20,203     26     177         20,406  
 

Accretion of asset retirement obligations

    1,572     33     18         1,623  
 

General and administrative, net of amounts capitalized

    9,206         118     (88 )   9,236  
                       
   

Total expenses

    64,464     (119 )   880     (1,113 )   64,112  
                       

Income (loss) from operations

    13,971     522     326         14,819  

FINANCING COSTS AND OTHER:

                               
 

Interest expense, net

    17,071         (1,066 )       16,005  
 

Amortization of deferred loan costs

    592                 592  
 

Commodity derivative losses (gains), net

    (38,572 )               (38,572 )
                       
   

Total financing costs and other

    (20,909 )       (1,066 )       (21,975 )
                       

Equity in subsidiary income

    1,187             (1,187 )    
                       

Income (loss) before income taxes

    36,067     522     1,392     (1,187 )   36,794  

Income tax provision (benefit)

    (727 )   199     528          
                       

Net income (loss)

  $ 36,794   $ 323   $ 864   $ (1,187 ) $ 36,794  
                       

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)


CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2010 (Unaudited)
(in thousands)

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

REVENUES:

                               
 

Oil and natural gas sales

  $ 209,106   $ 10,227   $   $   $ 219,333  
 

Other

    3,574     67     3,801     (3,549 )   3,893  
                       
   

Total revenues

    212,680     10,294     3,801     (3,549 )   223,226  
                       

EXPENSES:

                               
 

Lease operating expenses

    60,143     2,738     1,271         64,152  
 

Production and property taxes

    4,798     405     111         5,314  
 

Transportation expense

    9,766     13         (3,290 )   6,489  
 

Depletion, depreciation and amortization

    55,957     1,831     403         58,191  
 

Accretion of asset retirement obligations

    4,369     229     51         4,649  
 

General and administrative, net of amounts capitalized

    26,124     2,236     334     (259 )   28,435  
                       
   

Total expenses

    161,157     7,452     2,170     (3,549 )   167,230  
                       

Income (loss) from operations

    51,523     2,842     1,631         55,996  
                       

FINANCING COSTS AND OTHER:

                               
 

Interest expense, net

    33,374     (1 )   (2,834 )       30,539  
 

Amortization of deferred loan costs

    1,855                 1,855  
 

Interest rate derivative losses (gains), net

    36,848                 36,848  
 

Commodity derivative losses (gains), net

    (75,931 )               (75,931 )
                       
     

Total financing costs and other

    (3,854 )   (1 )   (2,834 )       (6,689 )
                       

Equity in subsidiary income

    4,531             (4,531 )    
                       

Income (loss) before income taxes

    59,908     2,843     4,465     (4,531 )   62,685  

Income tax provision (benefit)

    (3,177 )   1,080     1,697         (400 )
                       

Net income (loss)

  $ 63,085   $ 1,763   $ 2,768   $ (4,531 ) $ 63,085  
                       

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)


CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2011 (Unaudited)
(in thousands)

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

REVENUES:

                               
 

Oil and natural gas sales

  $ 240,345   $ 1,188   $   $   $ 241,533  
 

Other

    3,590     42     3,413     (3,168 )   3,877  
                       
   

Total revenues

    243,935     1,230     3,413     (3,168 )   245,410  

EXPENSES:

                               
 

Lease operating expense

    70,055     46     1,259         71,360  
 

Property and production taxes

    5,020     (336 )   99         4,783  
 

Transportation expense

    9,927             (2,904 )   7,023  
 

Depletion, depreciation and amortization

    63,265     78     467         63,810  
 

Accretion of asset retirement obligations

    4,669     97     55         4,821  
 

General and administrative, net of amounts capitalized

    27,801     1     351     (264 )   27,889  
                       
   

Total expenses

    180,737     (114 )   2,231     (3,168 )   179,686  
                       

Income (loss) from operations

    63,198     1,344     1,182         65,724  

FINANCING COSTS AND OTHER:

                               
 

Interest expense, net

    47,826         (3,148 )       44,678  
 

Amortization of deferred loan costs

    1,715                 1,175  
 

Interest rate derivative losses (gains), net

    1,083                 1,083  
 

Loss on extinguishment of debt

    1,357                 1,357  
 

Commodity derivative losses (gains), net

    (15,001 )               (15,001 )
                       
     

Total financing costs and other

    36,980         (3,148 )       33,832  
                       

Equity in subsidiary income

    3,518             (3,518 )    
                       

Income (loss) before income taxes

    29,736     1,344     4,330     (3,518 )   31,892  

Income tax provision (benefit)

    (2,156 )   511     1,645          
                       

Net income (loss)

  $ 31,892   $ 833   $ 2,685   $ (3,518 ) $ 31,892  
                       

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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
NINE MONTHS ENDED SEPTEMBER 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

  $ 86,187   $ 4,811   $ 4,961   $   $ 95,959  

CASH FLOWS FROM INVESTING ACTIVITIES:

                               
 

Expenditures for oil and natural gas properties

    (147,977 )   (942 )   (3,434 )       (152,353 )
 

Acquisitions of oil and natural gas properties

    (2,645 )               (2,645 )
 

Expenditures for property and equipment and other

    (2,331 )               (2,331 )
 

Proceeds from sale of oil and natural gas properties

        98,103             98,103  
                       
   

Net cash provided by (used in) investing activities

    (152,953 )   97,161     (3,434 )       (59,226 )

CASH FLOWS FROM FINANCING ACTIVITIES:

                               
 

Net proceeds from (repayments of) intercompany borrowings

    103,500     (101,973 )   (1,527 )        
 

Proceeds from long-term debt

    105,000                 105,000  
 

Principal payments on long-term debt

    (152,570 )               (152,570 )
 

Payments for deferred loan costs

    (281 )               (281 )
 

Proceeds from stock incentive plans and other

    10,709                 10,709  
                       
   

Net cash provided by (used in) financing activities

    66,358     (101,973 )   (1,527 )       (37,142 )
                       
 

Net increase (decrease) in cash and cash equivalents

    (408 )   (1 )           (409 )
 

Cash and cash equivalents, beginning of period

    418     1             419  
                       
 

Cash and cash equivalents, end of period

  $ 10   $   $   $   $ 10  
                       

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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
NINE MONTHS ENDED SEPTEMBER 30, 2011 (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

  $ 60,262   $ 1,463   $ 4,843   $   $ 66,568  

CASH FLOWS FROM INVESTING ACTIVITIES:

                               
 

Expenditures for oil and natural gas properties

    (187,107 )   66     (2,426 )       (189,467 )
 

Acquisitions of oil and natural gas properties

    (213 )               (213 )
 

Expenditures for property and equipment and other

    (1,088 )               (1,088 )
                       
   

Net cash provided by (used in) investing activities

    (188,408 )   66     (2,426 )       (190,768 )

CASH FLOWS FROM FINANCING ACTIVITIES:

                               
 

Net proceeds from (repayments of) intercompany borrowings

    3,946     (1,529 )   (2,417 )        
 

Proceeds from long-term debt

    563,000                 563,000  
 

Principal payments on long-term debt

    (515,311 )               (515,311 )
 

Payments for deferred loan costs

    (12,548 )               (12,548 )
 

Proceeds from issuance of common stock

    82,800                 82,800  
 

Stock issuance costs

    (629 )               (629 )
 

Proceeds from stock incentive plans and other

    1,873                 1,873  
                       
   

Net cash provided by (used in) financing activities

    123,131     (1,529 )   (2,417 )       119,185  
                       
 

Net increase (decrease) in cash and cash equivalents

    (5,015 )               (5,015 )
 

Cash and cash equivalents, beginning of period

    5,024                 5,024  
                       
 

Cash and cash equivalents, end of period

  $ 9   $   $   $   $ 9  
                       

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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, 2010 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. In recent years, the exploration, exploitation and development of the onshore Monterey shale formation has taken a fundamental role in our corporate strategy, and efforts to expand our knowledge of the onshore formation have increased significantly. A substantial portion of our production is from offshore wells targeting the fractured Monterey shale formation, and we believe that there are significant opportunities relating to the Monterey shale formation onshore as well.

        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.

Recent Events

        On August 26, 2011, our board of directors received a proposal from our chairman and chief executive officer, Timothy Marquez, to acquire all of our outstanding shares of common stock of which Mr. Marquez is not the beneficial owner for $12.50 per share in cash (the "Marquez Proposal"). Mr. Marquez is the beneficial owner of approximately 50.3% of our common stock. According to the proposal letter, Mr. Marquez will form an acquisition vehicle for the purpose of completing the acquisition. The proposal is subject to, among other things, Mr. Marquez being able to secure financing with acceptable terms. The board of directors has formed a special committee comprised of all independent directors to evaluate and consider this proposal as well as third party alternatives. As of October 31, 2011, no decisions have been made by the special committee with respect to the Company's response to the proposal. There can be no assurance that any definitive offer will be made, that any agreement will be executed or that this or any other transaction will be approved or consummated. See Part II, Item 1A. "Risk Factors" of this Quarterly Report on Form 10-Q.

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 2011 is $250 million, which was increased from $200 million in September 2011 to include costs associated with construction of the onshore pipeline to transport crude oil from the South Ellwood field, as well as to retain drilling rigs in the West Montalvo field, the Sevier field and in the Sacramento Basin for the remainder of the year. Approximately $188 million of the $250 million budget was expended in the first nine months of 2011. We have budgeted approximately 70% or $175 million for Southern California and 30% or $75 million for the Sacramento Basin. Of the $175 million allocated to Southern California, approximately $109 million is scheduled to be deployed

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to onshore Monterey shale activities with the remainder going to activities at legacy Southern California fields. We are in the process of developing our 2012 capital budget. Overall, we expect capital expenditures in 2012 will likely be below 2011 levels but anticipate increased spending at legacy Southern California fields, which received approximately 25% of the 2011 capital budget but will likely receive about 40% of the capital allocation. The remaining 60% of the 2012 capital budget will be allocated between onshore Monterey shale activities and the Sacramento Basin. We have experienced recent success at our Sevier field (see "—Southern California—Onshore Monterey Shale"), and the allocation of the remainder of our planned 2012 capital expenditures could be impacted by the results of the next few wells drilled at Sevier.

        The aggregate levels of capital expenditures for the remainder of 2011 and 2012, 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 employed. 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 2011 capital spending program.

Southern California—Exploitation and Development

        In the West Montalvo field, we have pursued an active workover, recompletion and return to production program that has resulted in significant production gains since we acquired the field in May 2007. 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. Earlier this year we secured permits to drill seven wells targeting offshore locations and two wells targeting onshore locations; we spud the first of these wells, an onshore well, during the second quarter and we completed the well early in the third quarter. We spud two wells, both targeting offshore locations, during the third quarter and plan to drill three additional offshore locations during the fourth quarter, one of which was spud in October. We have also performed five recompletions at West Montalvo during the first nine months of the year.

        In the Sockeye field, we redrilled two inactive wells that target the Monterey shale formation during the first nine months of the year. Our 2011 capital expenditure budget contemplates minimal activity levels at Sockeye during the remaining quarter of the year.

        At the South Ellwood field, we continue to work on advancing the permitting process for three of the five proved undeveloped locations on our existing leases and continue to perform the facilities work necessary to begin drilling those locations. Our 2011 capital expenditure budget includes plans to perform recompletions on a number of wells. We began these recompletions during the third quarter and expect to continue through the end of the year.

        In addition, during the third quarter of 2011 our subsidiary Ellwood Pipeline, Inc. received the approvals necessary to begin construction of a common carrier pipeline that will allow us to transport our oil from the field to refiners without the use of a barge or the marine terminal we currently use. Construction of the pipeline began in the third quarter and, if certain project milestones are met during the fourth quarter, the project could be completed during the first quarter of 2012. As a result of the pipeline approval, the estimated reserve life of the South Ellwood field is expected to be extended by approximately 30 years and proved reserves in the field have increased by approximately 9.0 MMBOE, based on SEC pricing as of September 30, 2011.

Southern California—Onshore Monterey Shale

        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

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advantageous. To date, our onshore Monterey shale acreage position totals approximately 252,000 gross and 168,000 net acres and is located primarily in three basins: Santa Maria, Salinas Valley and San Joaquin. We also have an additional 60,000 gross and 46,000 net acres with Monterey shale production or potential which are held by production at our legacy Southern California fields.

        During the first nine months of 2011 we spud nine wells, including three horizontal wells, and set casing on ten wells (including wells spud last year). In total, since the beginning of 2010 through the third quarter of 2011, we have spud 21 wells (15 vertical and six horizontal), of which 18 have had casing set (12 vertical and six horizontal) and two wells, both vertical, were used as pilot holes for two horizontal wells. We currently have one rig drilling in the Sevier field and plan to keep the rig operating through the end of the year and to spud two additional wells during the fourth quarter (one of which was spud in October). In addition, earlier this year, we completed the second and final phase of a 3-D seismic shoot in the San Joaquin area which covered approximately 500 square miles and we continue to analyze the data from the shoot.

        We have been encouraged by the scientific information collected thus far, particularly in two of our prospect areas (the Sevier field in the San Joaquin Basin and the South Salinas field in the Salinas Valley), but to date have not seen material levels of production from the program. At Sevier, we have spud four vertical wells during 2011 (including the well spud in October). Our second well drilled during the year at Sevier was completed in September and had a peak 24-hour gross production rate of 221 barrels of oil equivalent. The well has produced from one zone with a stabilized seven day gross rate of approximately 190 barrels of oil equivalent per day and has averaged approximately 165 gross barrels of oil equivalent per day over a 26-day period. We completed this well at the lowest zone in the wellbore. The zone exhibited limited log response, but has produced commercial levels of oil. As a result, we are planning to reevaluate our existing wellbores for additional recompletion opportunities. The results from the next few wells drilled at Sevier (two in the fourth quarter of 2011) could impact how we decide to allocate funding in our 2012 budget.

Sacramento Basin—Exploitation and Development

        In the Sacramento Basin, we continue to pursue our infill drilling program in the greater Grimes and Willows fields. During the first nine months of 2011, we spud 35 wells and performed 174 recompletions in the basin. 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 with 18 wells fractured during the first nine months of 2011. In early 2011 we drilled a successful exploratory well on an anomaly which we discovered using 3D seismic data we acquired with leasehold in 2009. The well has produced at sustained net rates of more than 2.5 million cubic feet per day and has enabled us to extend the boundaries of the Grimes field. We have drilled four additional wells along this trend; one well was plugged and abandoned, two wells have produced at sustained net rates of approximately 1.5 and 0.8 million cubic feet per day, and one well is currently being completed.

        We have reduced our activity levels in the basin in recent years as a result of depressed natural gas prices and our increased focus on our oil-based projects including Monterey shale activities. Our 2011 capital expenditure budget for the basin includes plans for approximately 40 wells, 220 recompletions, and 20 fracs.

Acquisitions and Divestitures

        Sale of Cat Canyon Field.    In December 2010, we sold our interests in the Cat Canyon field for $8.7 million (after closing adjustments).

        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

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$98.1 million (after closing adjustments and related expenses). We retained our 22.3% reversionary working interest in the Hastings Complex.

        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. We employ a hedging strategy to reduce the variability of the prices we receive for our production and provide a minimum revenue stream. As of October 31, 2011 we had hedge contract floors covering 8,000 barrels of oil per day and 60 million cubic feet of natural gas per day for the remainder of 2011. We have also secured hedge contracts for portions of our 2012 and 2013 production. See "Quantitative and Qualitative Disclosures About Market Risk—Commodity Derivative Transactions" for further details concerning our hedging activities. Additionally, the sales contracts under which we currently sell a significant portion of our oil are based on the NYMEX WTI ("WTI") crude price index and these contracts will expire at the end of the first quarter of 2012. We expect to enter into new sales contracts based on certain Southern California crude price indexes, which have recently traded at a premium to WTI and have more closely tracked with the Inter-Continental Exchange Brent crude price index ("Brent"). We also expect to be able to secure more favorable sales contracts related to oil produced from our South Ellwood field once the onshore pipeline is completed because we will be able to market our oil to a greater number of refineries.

        Expected Production.    We expect our 2011 average daily production volumes to be approximately 17,500 BOE per day, which is roughly flat with average daily production from our legacy assets in 2010. We originally projected flat production from our legacy assets and 2,000 BOE per day growth from our onshore Monterey shale project. The impact of the projected growth from our onshore Monterey shale project diminished as the year progressed as a result of delays in obtaining completion, evaluation and stimulation services and drilling results. At this point in the year we do not expect 2011 average daily production to be meaningfully impacted by onshore Monterey shale volumes. We continue to have positive long-term expectations for the project and we believe that it could result in significant production growth in subsequent years. Given our expected increase in capital spending related to our oil producing legacy Southern California assets in 2012, we expect the production ratio of oil to natural gas to increase in 2012 relative to 2011. Our expectations with respect to future production rates are subject to a number of uncertainties, including those associated with third party services, the availability of drilling rigs, oil and natural gas prices, events resulting in unexpected downtime, permitting issues, drilling success rates, including our ability to identify productive intervals and the drilling and completion techniques necessary to achieve commercial production in the onshore Monterey shale on a broader scale, 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, 2010.

        Lease Operating Expenses.    Lease operating expenses ("LOE") of $14.90 per BOE for the first nine months of 2011 were higher than our full year 2010 results of $12.65 per BOE. We expect our 2011 LOE per BOE to be higher relative to 2010 primarily due to certain maintenance projects at a number of our fields, which are expected to continue through the fourth quarter and into 2012. Our expectations with respect to future expenses are subject to numerous risks and uncertainties, including those described and referenced in the preceding paragraph.

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        Property and Production Taxes.    Property and production taxes of $1.00 per BOE for the first nine months of 2011 were relatively flat when compared to our full year 2010 results of $1.01 per BOE. We expect our full year 2011 property and production taxes to remain relatively flat on a per BOE basis compared to our 2010 results. As with lease operating expenses, our expectations with respect to future property and production taxes are subject to numerous risks and uncertainties.

        General and Administrative Expenses.    General and administrative expenses remained flat at $4.79 per BOE (excluding share-based compensation charges of $0.85 per BOE and costs of $0.19 per BOE related to the evaluation by the special committee of the Marquez Proposal) in the first nine months of 2011 compared to $4.78 per BOE for 2010 (excluding share-based compensation charges of $0.68 per BOE and one-time charges of $0.19 per BOE for severance payments resulting from the sale of our Texas producing properties). Excluding share-based compensation charges, severance charges and special committee-related charges, on a per BOE basis, we expect our G&A costs to remain relatively flat for the full year 2011 compared to 2010. As with our lease operating expenses and property and production taxes, 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 nine months of 2011 of $13.32 per BOE increased from our full year 2010 DD&A of $11.79 per BOE. We expect our 2011 DD&A to increase on a per BOE basis compared to our full year 2010 results. As with lease operating expenses, property and production taxes and G&A expenses, our expectations with respect to DD&A expenses are subject to numerous risks and uncertainties.

        Interest Expense.    As a result of the refinancing of our second lien term loan in the first quarter of 2011 (see "—Capital Resources and Requirements"), we replaced $455.3 million of variable rate debt with $500.0 million of 8.875% fixed rate debt. Additionally, because our second lien term loan was subject to variable interest rates, we had entered into interest rate derivative contracts to mitigate our interest rate risk and, as a result, $500.0 million of variable rate borrowings effectively bore interest at approximately 7.8%. In conjunction with the refinancing transaction in the first quarter of 2011, we settled the interest rate derivative contracts.

        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.

        Income Tax Expense (Benefit).    We incurred losses before income taxes in 2008 and 2009. These losses and expected future taxable losses were a key consideration that led us to conclude that we should maintain a full valuation allowance against our net deferred tax assets at December 31, 2010 and September 30, 2011 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. Future events or new evidence which may lead us to conclude that it is more likely than not that our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings; consistent and sustained pre-tax earnings; sustained or continued improvements in oil and natural gas commodity prices; consistent, meaningful production and proved reserves from our onshore Monterey shale project; and meaningful production and proved reserves from the CO2 flood at the Hastings field. We will continue to evaluate whether the valuation allowance is needed in future reporting periods.

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        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 nine months ended September 30, 2010 and 2011. This information reflects the actual historical results of our operations. 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
September 30,
  Nine Months Ended
September 30,
 
 
  2010   2011   2010   2011  

Production Volume:

                         
 

Oil (MBbls)(1)

    682     594     2,163     1,821  
 

Natural gas (MMcf)

    5,892     5,966     17,405     17,812  
 

MBOE

    1,664     1,588     5,064     4,790  

Daily Average Production Volume:

                         
 

Oil (Bbls/d)

    7,413     6,457     7,923     6,670  
 

Natural gas (Mcf/d)

    64,043     64,848     63,755     65,245  
 

BOE/d

    18,087     17,265     18,549     17,544  

Oil Price per Bbl Produced (in dollars):

                         
 

Realized price

  $ 65.88   $ 87.24   $ 67.20   $ 90.06  
 

Realized commodity derivative gain (loss)

    (1.28 )   (5.01 )   (1.40 )   (3.97 )
                   
 

Net realized price

  $ 64.60   $ 82.23   $ 65.80   $ 86.09  
                   

Natural Gas Price per Mcf (in dollars):

                         
 

Realized price

  $ 3.93   $ 4.18   $ 4.46   $ 4.16  
 

Realized commodity derivative gain (loss)

    1.99     0.93     1.55     0.91  
                   
 

Net realized price

  $ 5.92   $ 5.11   $ 6.01   $ 5.07  
                   

Expense per BOE:

                         
 

Lease operating expenses

  $ 12.44   $ 18.06   $ 12.67   $ 14.90  
 

Property and production taxes

    1.05     1.13     1.05     1.00  
 

Transportation expenses

    1.65     1.49     1.28     1.47  
 

Depreciation, depletion and amortization

    11.70     12.85     11.49     13.32  
 

General and administrative expense(2)

    4.97     5.82     5.62     5.82  
 

Interest expense

    6.08     10.08     6.03     9.33  

(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)
Net of amounts capitalized.

Comparison of Quarter Ended September 30, 2011 to Quarter Ended September 30, 2010

        Oil and Natural Gas Sales.    Oil and natural gas sales increased $8.4 million (12%) in the third quarter of 2011 to $77.3 million compared to $68.9 million in the third quarter of 2010. Sales in the third quarter of 2011 were primarily affected by higher oil and natural gas prices compared to the third quarter of 2010, partially offset by lower oil production in the third quarter of 2011 as described below.

        Oil sales increased by $6.7 million (14%) in the third quarter of 2011 to $52.4 million compared to $45.7 million in the third quarter of 2010. Oil production decreased by 13%, with production of 594

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MBbls in the third quarter of 2011 compared to 682 MBbls in the third quarter of 2010. The decrease is primarily due to the following during the third quarter of 2011: (i) scheduled downtime for planned maintenance at Platform Holly, (ii) downtime for certain wells at Platform Holly and the West Montalvo field to complete workover activities, and (iii) natural production decline from the Sockeye, South Ellwood and West Montalvo fields. Our average realized price for oil increased $21.36 per Bbl (32%) from $65.88 per Bbl in the third quarter of 2010 to $87.24 per Bbl for the third quarter of 2011.

        Natural gas sales increased $1.7 million (8%) in the third quarter of 2011 to $24.9 million compared to $23.2 million in the third quarter of 2010. Natural gas production increased slightly (1%) in the third quarter of 2011, with production of 5,966 MMcf compared to 5,892 MMcf in the third quarter of 2010. The increase is primarily the result of successful drilling and recompletion activity in the Sacramento Basin in the latter half of 2010 and the first nine months of 2011. Our average realized price for natural gas increased $0.25 per Mcf (6%) from $3.93 per Mcf in the third quarter of 2010 to $4.18 per Mcf in the third quarter of 2011.

        Other Revenues.    Other revenues remained relatively constant at $1.6 million in the third quarter of 2011 compared to $1.5 million in the third quarter of 2010. Effective April 2010, we entered into a contract 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 a major portion of the revenues from those activities.

        Lease Operating Expenses.    Lease operating expenses ("LOE") increased $8.0 million (39%) to $28.7 million in the third quarter of 2011 from $20.7 million in the third quarter of 2010. On a per unit basis, LOE increased by $5.62 per BOE from $12.44 in the third quarter of 2010 to $18.06 in the third quarter of 2011. The increase in LOE is primarily due to (i) costs incurred to return Platform Grace to production, which had been shut-in since the end of 2008, (ii) costs related to the planned maintenance at Platform Holly and (iii) certain non-recurring maintenance performed at Dos Cuadras, Platform Gail and Platform Holly in the third quarter of 2011.

        Property and Production Taxes.    Property and production taxes remained relatively constant at $1.8 million in the third quarter of 2011 compared to $1.7 million in the third quarter of 2010. On a per BOE basis, property and production taxes increased slightly from $1.05 per BOE in the third quarter of 2010 to $1.13 per BOE in the third quarter of 2011.

        Transportation Expenses.    Transportation expenses decreased $0.4 million (14%) to $2.4 million in the third quarter of 2011 compared to $2.8 million in the third quarter of 2010. We entered into a contract related to the time-charter of a double-hulled barge to transport oil produced from our South Ellwood field in April 2010. 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"). The decrease in transportation expense is primarily due to a demurrage reimbursement received in connection with sub-charter activities.

        Depletion, Depreciation and Amortization (DD&A).    DD&A expense increased $0.9 million (5%) to $20.4 million in the third quarter of 2011 from $19.5 million in the third quarter of 2010. The increase is due to a higher depletion rate which resulted from a higher amortizable base at the end of the third quarter of 2011 compared to the end of the third quarter of 2010. DD&A expense on a per unit basis increased by $1.15 per BOE from $11.70 per BOE for the third quarter of 2010 to $12.85 per BOE for the third quarter of 2011.

        Accretion of Abandonment Liability.    Accretion expense remained relatively constant at $1.6 million in the third quarter of 2011 compared to $1.5 million in the third quarter of 2010.

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        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
September 30,
 
 
  2010   2011  

General and administrative costs

  $ 11,770   $ 12,247  

Share-based compensation costs

    1,660     2,430  

Special Committee-related costs

        892  

General and administrative costs capitalized

    (5,166 )   (6,333 )
           
 

General and administrative expense

  $ 8,264   $ 9,236  
           

        G&A expenses increased $0.9 million (12%) from $8.3 million in the third quarter of 2010 to $9.2 million in the third quarter of 2011. The increase is primarily due to costs incurred related to the evaluation by the special committee of the board of directors of the Marquez Proposal. Excluding the effect of the non-cash share based compensation expense and special committee-related costs, G&A expense increased to $4.43 per BOE in the third quarter of 2011 from $4.31 per BOE in the third quarter of 2010.

        Interest Expense, Net.    Interest expense, net of interest income, increased $5.9 million (58%) from $10.1 million in the third quarter of 2010 to $16.0 million in the third quarter of 2011. The increase was primarily the result of the refinancing of our second lien term loan in February 2011 with the issuance of our 8.875% senior notes. The interest rate on our second lien term loan, which was outstanding during the third quarter of 2010, averaged approximately 4.4% per annum during that period.

        Amortization of Deferred Loan Costs.    Amortization of deferred loan costs was $0.6 million in the third quarter of 2011 compared to $0.5 million in the third quarter of 2010. The costs incurred relate to our loan agreements and are amortized over the estimated lives of the agreements.

        Interest Rate Derivative (Gains) Losses, Net.    In conjunction with the retirement of our second lien term loan in February 2011, we settled our outstanding interest rate swap contracts for $38.1 million in the first quarter of 2011. In the third quarter of 2010, we recognized an unrealized interest rate derivative loss of $6.6 million and a realized interest rate derivative loss of $4.5 million.

        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
September 30,
 
 
  2010   2011  

Realized commodity derivative (gains) losses

  $ (10,863 ) $ (2,571 )

Amortization of commodity derivative premiums

    5,657     1,990  

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

    (15,690 )   (37,991 )
           
 

Commodity derivative (gains) losses

  $ (20,896 ) $ (38,572 )
           

        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 third quarter of 2011 and the same period in 2010 reflect the settlement of contracts at prices below the relevant strike prices. Unrealized commodity derivative (gains) losses

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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 and expected future taxable losses were a key consideration that led us to conclude that we should maintain a full valuation allowance against our net deferred tax assets at December 31, 2010 and September 30, 2011 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. However, we continue to evaluate the existing evidence to determine the point at which we can conclude that it is more likely than not that we will be able to realize our net deferred tax assets and, as a result, reverse all or a portion of the valuation allowance. Due to our valuation allowance, there was no income tax expense (benefit) recorded for the three month period ended September 30, 2011. The income tax benefit of $0.2 million for the three months ended September 30, 2010 related to a reduction of prior year state income taxes.

        Net Income (Loss).    Net income for the third quarter of 2011 was $36.8 million compared to net income of $15.4 million for the same period in 2010. The change between periods is the result of the items discussed above.

Comparison of Nine Months Ended September 30, 2011 to Nine Months Ended September 30, 2010

        Oil and Natural Gas Sales.    Oil and natural gas sales increased $22.2 million (10%) to $241.5 million for the nine months ended September 30, 2011 from $219.3 million for the same period in 2010. The increase was primarily due to an increase in realized oil prices, partially offset by a decrease in oil production and a decrease in realized natural gas prices, as described below.

        Oil sales increased by $25.6 million (18%) for the first nine months of 2011 to $167.3 million compared to $141.7 million in the first nine months of 2010. Oil production decreased by 16%, with production of 1,821 MBbls in the first nine months of 2011 compared to 2,163 MBbls in the first nine months of 2010. The production decrease was partially due to the sales of our remaining producing properties in Texas in the second quarter of 2010. Excluding production from the Texas properties, production decreased by 230 MBbls (11%) from 2,051 MBbls in the first nine months of 2010 to 1,821 MBbls in the first nine months of 2011. The decrease is primarily due to natural production decline at the Sockeye, South Ellwood and West Montalvo fields. Our average realized price for oil increased $22.86 (34%) from $67.20 per Bbl in the first nine months of 2010 to $90.06 per Bbl for the first nine months of 2011.

        Natural gas sales decreased $3.5 million (4%) in the first months of 2011 to $74.2 million compared to $77.7 million in the first nine months of 2010. Natural gas production increased by 407 MMcf (2%) with production of 17,812 MMcf in the first nine months of 2011 compared to 17,405 MMcf in the first nine months of 2010. Excluding production from the Texas properties, production increased by 748 MMcf (4%) from 17,064 MMcf in the first nine months of 2010 to 17,812 MMcf in the first nine months of 2011. The increase is primarily the result of successful drilling and recompletion activity in the Sacramento Basin in the latter half of 2010 and the first nine months of 2011. Our average realized price for natural gas decreased $0.30 per Mcf (7%) from $4.46 per Mcf in the first nine months of 2010 to $4.16 per Mcf for the first nine months of 2011.

        Other Revenues.    Other revenues remained constant at $3.9 million in both the first nine months of 2011 and the first nine months of 2010. Effective April 2010, we entered into a contract related to the double- hulled barge that transports oil produced at our South Ellwood field (see "—Transportation

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Expenses"). The contract allows us to sub-charter the barge and retain a major portion of the revenues from those activities.

        Lease Operating Expenses.    Lease operating expenses ("LOE") increased $7.2 million (11%) to $71.4 million in the first nine months of 2011 from $64.2 million in the first nine months of 2010. Excluding the Texas properties, lease operating expenses increased $10.0 million (16%) from $61.4 million in the first nine months of 2010 to $71.4 million in the first nine months of 2011. The increase in LOE is primarily due to (i) costs incurred to return Platform Grace to production, which had been shut-in since the end of 2008 and (ii) certain non-recurring maintenance performed at Dos Cuadras, Platform Gail and Platform Holly in the third quarter of 2011. On a per unit basis, LOE increased by $2.23 per BOE from $12.67 in the first nine months of 2010 to $14.90 in the first nine months of 2011. Excluding the Texas assets, LOE per BOE increased from $12.55 per BOE in the first nine months of 2010 to $14.90 per BOE in the first nine months of 2011.

        Property and Production Taxes.    Property and production taxes decreased $0.5 million (10%) to $4.8 million in the first nine months of 2011 from $5.3 million in the first nine months of 2010. Property and production taxes were higher in the 2010 period primarily as a result of our Texas properties which were sold in the second quarter of 2010.

        Transportation Expenses.    Transportation expenses increased $0.5 million (8%) to $7.0 million in the first nine months of 2011 from $6.5 million in the first nine months of 2010. In April 2010, a transportation contract became effective and 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"). The increase in the first nine months of 2011 compared to the same period in 2010 was the result of the transportation contract being in place for the full nine months of the 2011 period compared to six months in the 2010 period.

        Depletion, Depreciation and Amortization (DD&A).    DD&A expense increased $5.6 million (10%) to $63.8 million in the first nine months of 2011 from $58.2 million in the first nine months of 2010. The increase is due to a higher depletion rate primarily due to higher amortizable bases at each of the quarterly periods in first nine months of 2011 compared to the same periods in the first nine months of 2010. DD&A expense on a per unit basis increased by $1.83 per BOE from $11.49 per BOE for the first nine months of 2010 to $13.32 per BOE for the first nine months of 2011.

        Accretion of Abandonment Liability.    Accretion expense remained relatively constant at $4.8 million in the first nine months of 2011 compared to $4.6 million in the first nine 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):

 
  Nine Months Ended
September 30,
 
 
  2010   2011  

General and administrative costs

  $ 39,208   $ 39,520  

Share-based compensation costs

    5,020     7,140  

One-time severance costs

    1,254      

Special Committee-related costs

        892  

General and administrative costs capitalized

    (17,047 )   (19,663 )
           
 

General and administrative expense

  $ 28,435   $ 27,889  
           

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        G&A expense decreased $0.5 million (2%) to $27.9 million in the first nine months of 2011 from $28.4 million in the first nine months of 2010. The overall decrease in G&A costs was primarily due to (i) one-time severance payments of $1.3 million made in 2010 related to the sale of our Texas properties and the related closure of our Texas operations and (ii) higher capitalization in the second and third quarters of 2011 as a result of an increased focus on onshore Monterey shale activities. These decreases were partially offset by increased travel costs in the first nine months of 2011 and costs incurred in the third quarter of 2011 related to the evaluation by the special committee of the board of directors of the Marquez Proposal. Excluding the effect of the non-cash share-based compensation expense, one-time severance charges and special committee-related costs, G&A expense on a BOE basis was relatively flat at $4.79 per BOE in the first nine months of 2011 compared to $4.73 per BOE in the first nine months of 2010.

        Interest Expense, Net.    Interest expense, net of interest income, increased $14.2 million (46%) from $30.5 million in the first nine months of 2010 to $44.7 million in the first nine months of 2011. The increase was primarily the result of the refinancing of our second lien term loan in February 2011 with the issuance of our 8.875% senior notes. The interest rate on our second lien term loan, which was outstanding during the first nine months of 2010, averaged approximately 4.4% per annum during that period.

        Amortization of Deferred Loan Costs.    Amortization of deferred loan costs was $1.7 million in the first nine months of 2011 compared to $1.9 million in the first nine months of 2010. The costs incurred relate to our loan agreements and are amortized over the estimated lives of the agreements.

        Interest Rate Derivative (Gains) Losses, Net.    In conjunction with the retirement of our second lien term loan in February 2011, we settled our outstanding interest rate swap contracts for $38.1 million. The result of settlement of the contracts and other activity in the first nine months of 2011 was an unrealized interest rate derivative gain of $40.1 million and a realized interest rate derivative loss of $41.1 million. In the first nine months of 2010, we recognized an unrealized interest rate derivative loss of $23.3 million and a realized interest rate derivative loss of $13.6 million.

        Loss on Extinguishment of Debt.    We recognized a loss on extinguishment of debt in the first nine months of 2011 of $1.4 million resulting from the repayment of our second lien term loan. The loss related primarily to the write off of unamortized deferred financing costs associated with the second lien term loan.

        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):

 
  Nine Months Ended
September 30,
 
 
  2010   2011  

Realized commodity derivative (gains) losses

  $ (23,869 ) $ (11,546 )

Amortization of commodity derivative premiums

    16,972     5,970  

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

    (69,034 )   (9,425 )
           
 

Commodity derivative (gains) losses

  $ (75,931 ) $ (15,001 )
           

        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 nine months of 2011 and the first nine months of 2010 reflect the settlement of contracts at prices below the relevant strike prices. In addition, we unwound certain oil

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swaps in the second quarter of 2011 and realized a non-recurring gain of $2.0 million which is reflected in realized commodity derivative (gains) losses. 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 and expected future taxable losses were a key consideration that led us to conclude that we should maintain a full valuation allowance against our net deferred tax assets at December 31, 2010 and September 30, 2011 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. However, we continue to evaluate the existing evidence to determine the point at which we can conclude that it is more likely than not that we will be able to realize our net deferred tax assets and, as a result, reverse all or a portion of the valuation allowance. Due to our valuation allowance, there was no income tax expense (benefit) recorded for the nine month period ended September 30, 2011. The income tax benefit of $0.4 million for the nine months ended September 30, 2010 relates to an increase in the estimated net operating loss carryback claim for the 2003 through 2005 tax years and a reduction in the amount owed for prior year state income taxes.

        Net Income (Loss).    Net income for the first nine months of 2011 was $31.9 million compared to net income of $63.1 million for the same period in 2010. 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

 
  Nine Months Ended
September 30,
 
 
  2010   2011  
 
  (in thousands)
 

Cash provided by operating activities

  $ 95,959   $ 66,568  

Cash (used in) provided by investing activities

    (59,226 )   (190,768 )

Cash (used in) provided by financing activities

    (37,142 )   119,185  

        Net cash provided by operating activities was $66.6 million in the first nine months of 2011 compared with $96.0 million in the 2010 period. Cash flows from operating activities in the first nine months of 2011 as compared to the 2010 period were unfavorably impacted by the settlement of our interest rate derivative contracts in the first quarter of 2011 for $38.1 million (see "—Capital Resources and Requirements"), partially offset by higher realized oil prices during the 2011 period.

        Net cash used in investing activities was $190.8 million in the first nine months of 2011 compared with $59.2 million in the 2010 period. The primary investing activities in the first nine months of 2011 were $189.5 million in capital expenditures on oil and natural gas properties related to our capital expenditure program. The primary investing activities in the first nine months of 2010 were $152.4 million in capital expenditures on oil and natural gas properties related to our capital expenditure program, partially offset by the receipt of $98.1 million in net cash proceeds from the sales of our Texas producing properties in the second quarter of 2010.

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        Net cash provided by financing activities was $119.2 million in the first nine months of 2011 compared to net cash used of $37.1 million during the 2010 period. The primary financing activities in the first nine months of 2011 were the two capital raising transactions we completed as described below in "—Capital Resources and Requirements". In conjunction with the capital raising transactions, we repaid the outstanding principal of $455.3 million related to our second lien term loan. Additionally, subsequent to the transactions described below, we incurred net borrowings on our revolving credit facility of $38.0 million. The primary financing activities in the first nine months of 2010 were $16.9 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.

Capital Resources and Requirements

        In the first quarter of 2011, we completed two capital raising transactions which provided us with additional liquidity. First, we issued 4.6 million shares of common stock at a price to the public of $18.75 per share. We received net proceeds of approximately $82.2 million from the equity offering after deducting offering-related expenses. Second, we issued $500 million of 8.875% senior unsecured notes which are due in February 2019. We received net proceeds of approximately $490.3 million from the notes offering, after deducting offering-related expenses. The proceeds from the two transactions were used to repay the outstanding principal of $455.3 million and accrued interest of $1.6 million related to our second lien term loan, settle the related interest rate swap contracts for $38.1 million and repay the outstanding balance of $45.0 million on our revolving credit facility.

        We plan to make substantial capital expenditures in the future for the acquisition, exploration, exploitation and development of oil and natural gas properties. Our current budget for exploration, exploitation and development capital expenditures in 2011 is $250 million, of which we have incurred approximately $188 million during the first nine months of 2011. Although we are still in the process of developing our 2012 capital budget, we expect the budget will likely be below our 2011 levels. We expect to fund the remainder of our 2011 and our 2012 capital expenditures budgets primarily with cash flow from operations, supplemented with borrowings under our revolving credit facility. Additionally, we continue to pursue joint venture transactions related to our onshore Monterey shale project. We have significant flexibility to reduce capital expenditures if warranted by business conditions or limits on our capital resources. Uncertainties relating to our capital resources and requirements 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, results from our onshore Monterey shale program, which could lead us to accelerate or decelerate activities depending on the extent of our success in developing the program, 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 April 2011, we entered into a fourth amended and restated credit agreement governing our revolving credit facility, which has a maturity date of March 31, 2016. The agreement contains customary representations, warranties, events of default, indemnities and covenants, including covenants that restrict our ability to incur indebtedness 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 2011 or 2012, 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.

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        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 1.0%, plus (ii) an applicable margin ranging from 0.75% to 1.75%, 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 1.75% to 2.75%, 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 $500.0 million, but is limited by a borrowing base which is currently established at $200.0 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 11 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 October 31, 2011, we have $43.0 million outstanding under the facility and $153.2 million in available borrowing capacity.

        Second Lien Term Loan and 8.875% Senior Notes.    We entered into a $500.0 million senior secured second lien term loan agreement in May 2007. Prior to repayment as described below, the term loan facility was secured by a second priority lien on substantially all of our assets and was due to mature on May 8, 2014. Loans under the second lien term loan facility designated as "Base Rate Loans" bore 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" bore interest at LIBOR plus 4.00%.

        In February 2011, we issued $500 million in 8.875% senior unsecured notes due in February 2019 at par. Concurrently with the sale of the 8.875% senior notes, we repaid in full the outstanding principal balance of $455.3 million on the second lien term loan, plus accrued interest of $1.6 million.

        The 8.875% senior notes pay interest semi-annually in arrears on February 15 and August 15 of each year. We may redeem the notes prior to February 15, 2015 at a "make whole premium" defined in the indenture. Beginning February 15, 2015, we may redeem the notes at a redemption price of 104.438% of the principal amount and declining to 100% by February 15, 2017. The 8.875% senior notes are senior unsecured obligations and contain operational covenants that, among other things, limit our ability to make investments, incur additional indebtedness or create liens on our assets.

        11.50% 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

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and certain other means is limited by covenants in our debt agreements. In addition, pursuant to mandatory prepayment provisions in our revolving credit facility, 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 facility that require us to use some or all of the proceeds of such transactions to reduce amounts outstanding under the facility 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 September 30, 2011, we had no existing off-balance sheet arrangements, as defined under SEC rules, which 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.

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 commodity 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 or for other corporate purposes.

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

Commodity Derivative Transactions

        Commodity Derivative Agreements.    As of September 30, 2011, we had entered into various 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

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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)
 
 
  Weighted
Avg.
Barrels/day
  Weighted Avg.
Prices per Bbl
  Weighted
Avg.
MMBtu/day
  Weighted Avg.
Prices per
MMBtu
 

October 1 - December 31, 2011:

                         
 

Swaps

    1,000   $ 105.65     24,000   $ 4.44  
 

Collars(1)

    5,000   $ 50.00/$100.00       $  
 

Puts(1)

    2,000   $ 50.00     36,000   $ 5.92  

January 1 - December 31, 2012:

                         
 

Collars(1)

    6,500   $ 80.00/$118.15     13,400   $ 4.50/$5.25  
 

Puts(1)

    2,000   $ 60.00     37,300   $ 5.81  

January 1 - December 31, 2013:

                         
 

Collars

    3,900   $ 81.79/113.59     20,000   $ 4.50/$5.40  
 

Puts

      $     20,000   $ 5.00  

(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.

        We have also entered into certain oil and natural gas basis swaps. The oil basis swaps fix the differential between the WTI crude price index and the Brent crude price index. Historically the two price indexes have demonstrated a close correlation. The Southern California indexes on which we sell a significant percentage of our oil have historically demonstrated a close correlation with these two major crude oil benchmarks. Recently, however, the relationship between WTI and Brent has diverged, favoring Brent crude, and the Southern California indexes most relevant to us have continued to track their correlation to Brent prices. The oil basis swaps we have entered into attempt to fix the current premium Southern California indexes are realizing relative to WTI. The natural gas basis swaps fix the differential between the Henry Hub price and the PG&E Citygate price, the index on which the majority of our natural gas is sold. Our oil and natural gas basis swaps as of September 30, 2011 are presented below:

 
  Oil Basis Swaps
(NYMEX WTI)
  Natural Gas Basis Swaps
(NYMEX Henry Hub)
 
 
  Floating Index   Weighted Avg.
Bbls/Day
  Weighted
Avg. Basis
Differential to
NYMEX WTI
(per Bbl)
  Floating Index   Weighted Avg.
MMBtu/Day
  Weighted
Avg. Basis
Differential to
NYMEX HH
(per MMBtu)
 

Basis Swaps:

                                 
 

October 1 - December 31, 2011

  Brent Crude     3,700   $ 9.30   PG&E Citygate     57,224   $ 0.11  
 

January 1 - December 31, 2012

  Brent Crude     7,630   $ 6.90   PG&E Citygate     47,400   $ 0.28  
 

January 1 - December 31, 2013

  Brent Crude     3,900   $ 5.88         $  

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Portfolio of Derivative Transactions

        Our portfolio of commodity derivative transactions as of September 30, 2011 is summarized below:


Oil

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

Collar

  Key Bank   NYMEX     2,000   $ 50.00/$141.00     Oct 1 - Dec 31, 11  

Call Spread

  Key Bank   NYMEX     2,000   $ 141.00/$100.00     Oct 1 - Dec 31, 11  

Collar

  Credit Suisse   NYMEX     3,000   $ 50.00/$140.00     Oct 1 - Dec 31, 11  

Call Spread

  Credit Suisse   NYMEX     3,000   $ 140.00/$100.00     Oct 1 - Dec 31, 11  

Put

  Key Bank   NYMEX     2,000   $ 50.00     Oct 1 - Dec 31, 11  

Swap

  Scotia Capital   NYMEX     1,000   $ 105.65     Oct 1 - Dec 31, 11  

Basis Swap

  Bank of Montreal   NYMEX/Brent     3,700   $ 9.30     Oct 1 - Dec 31, 11  

Collar

  RBS   NYMEX     3,000   $ 60.00/$121.10     Jan 1 - Dec 31, 12  

Call (purchased)

  Bank of Montreal   NYMEX     2,000   $ 121.10     Jan 1 - Dec 31, 12  

Collar

  Bank of Montreal   NYMEX     1,500   $ 80.00/$110.85     Jan 1 - Dec 31, 12  

Collar

  Bank of Montreal   NYMEX     1,000   $ 85.00/$120.30     Jan 1 - Dec 31, 12  

Collar

  Scotia Capital   NYMEX     1,000   $ 85.00/$120.10     Jan 1 - Dec 31, 12  

Collar

  BNP Paribas   NYMEX     2,000   $ 85.00/$120.10     Jan 1 - Dec 31, 12  

Basis Swap

  Bank of Montreal   NYMEX/Brent     4,500   $ 7.28     Jan 1 - Mar 31, 12  

Basis Swap

  Bank of Montreal   NYMEX/Brent     2,950   $ 7.28     Apr 1 - Dec 31, 12  

Basis Swap

  Bank of Montreal   NYMEX/Brent     500   $ 7.15     Jan 1 - Mar 31, 12  

Basis Swap

  Bank of Montreal   NYMEX/Brent     550   $ 7.15     Apr 1 - Dec 31, 12  

Basis Swap

  Bank of Montreal   NYMEX/Brent     2,750   $ 6.90     Apr 1 - Dec 31, 12  

Basis Swap

  Bank of Montreal   NYMEX/Brent     2,250   $ 6.05     Apr 1 - Dec 31, 12  

Collar

  Credit Suisse   NYMEX     1,000   $ 80.00/$110.00     Jan 1 - Dec 31, 13  

Collar

  Credit Suisse   NYMEX     500   $ 80.00/$110.00     Jan 1 - Dec 31, 13  

Collar

  Credit Suisse   NYMEX     1,400   $ 85.00/$120.00