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

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Form 10-Q

Venoco, Inc.

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.

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

        As of June 30, 2011, there were 61,617,933 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 pursuit and receipt of approvals relating to the pipeline project 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:

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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;



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



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risks related to our level of indebtedness;



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our ability to replace oil and natural gas reserves;



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risks arising out of our hedging transactions;



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



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



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inaccuracy in reserve estimates and expected production rates;



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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;



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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;



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



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



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



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



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

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factors affecting the nature and timing of our capital expenditures;



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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;



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



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environmental liabilities;



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loss of senior management or technical personnel;



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natural disasters, including severe weather;



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



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risk factors discussed in this report; and



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other factors, many of which are beyond our control.

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VENOCO, INC.
Form 10-Q for the Quarterly Period Ended June 30, 2011

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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)

See notes to condensed consolidated financial statements.

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VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(In thousands, except per share amounts)

See notes to condensed consolidated financial statements.

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VENOCO, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

(UNAUDITED)

(In thousands)

See notes to condensed consolidated financial statements.

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VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In thousands)

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 June 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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

reserves from our 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 six months ended June 30, 2010 relates to an increase in the estimated net operating loss carryback claim for the 2003 through 2005 tax years. Due to the valuation allowance, no income tax expense or benefit was recorded for the six months ended June 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):

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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):

        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 June 30, 2011, the Company has incurred approximately $790,000 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 June 30, 2011.

        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 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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

2. ACQUISITIONS AND SALES OF PROPERTIES (Continued)

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):

        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 operating subsidiaries other than Ellwood Pipeline, Inc. The collateral also secures the Company's obligations to hedging counterparties that are also lenders, or affiliates of lenders, under the facility. Loans 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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

3. LONG-TERM DEBT (Continued)

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 July 29, 2011, the Company had no balance outstanding on the facility and had available borrowing capacity of $196.2 million under the facility, net of $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.

        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 June 30, 2011.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

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 contracts are effective. At June 30, 2011, the balance of unamortized net derivative premiums paid was $15.3 million, of which $4.0 million, $9.5 million and $1.8 million will be amortized in the remainder of 2011 and in 2012 and 2013, respectively.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

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

        As of June 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.

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(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.

        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 current

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

premium Southern California indexes are realizing relative to WTI and hedge the effect of future changes to the WTI-Brent relationship. 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 June 30, 2011 are presented below:

        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.

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

        Fair Value of Derivative Instruments.    The estimated fair values of derivatives included in the consolidated balance sheets at December 31, 2010 and June 30, 2011 are summarized below. The net fair value of the Company's derivatives changed by $11.4 million from a net liability of $9.0 million at

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

December 31, 2010 to a net asset of $2.4 million at June 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, and (iii) 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 Company has not designated any of its derivative contracts as hedging instruments. The main headings represent the balance sheet captions for the contracts presented.

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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

5. FAIR VALUE MEASUREMENTS (Continued)

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.

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

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

        Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of June 30, 2011 (in thousands).

        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.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

5. FAIR VALUE MEASUREMENTS (Continued)

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

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.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

6. ASSET RETIREMENT OBLIGATIONS (Continued)

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

7. CAPITAL STOCK

        The Company has 65.9 million shares of common stock issued or reserved for issuance at June 30, 2011. At June 30, 2011, the Company has 61.6 million common shares issued and outstanding, of which 2.9 million shares are restricted stock granted under the Company's 2005 stock incentive plan. At June 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 June 30, 2011, there are a total of 903,755 options outstanding with a weighted average exercise price of $13.90 ($6.00 to $20.00). The options vest over a four year period, with 20% vesting on the grant date and 20% vesting on each subsequent anniversary of the grant date. The options typically have a maximum life of 10 years. The options will generally vest upon a change in control of the Company.

        As of June 30, 2011, there were a total of 2,892,947 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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

8. SHARE-BASED PAYMENTS (Continued)

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 June 30, 2011, there was $22.3 million of total unrecognized compensation cost related to restricted stock, which is expected to be amortized over a weighted-average period of 3.0 years and a minimal amount compensation cost related to stock options remains to be recognized.

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

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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

8. SHARE-BASED PAYMENTS (Continued)

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

        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 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

        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 2011. 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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VENOCO, INC. AND SUBSIDIARIES

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.

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

        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. The Company has not accrued any amounts related to the SLC audit contentions or potential refunds.

        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 June 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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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 2011 (Unaudited)
(in thousands)

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
SIX MONTHS ENDED JUNE 30, 2011 (Unaudited)
(in thousands)

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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.

        Our average net production was 17,560 BOE/d in the second quarter of 2011, compared to 18,190 BOE/d in the second quarter of 2010 and 17,815 BOE/d in the first quarter of 2011. Excluding production from producing properties in Texas, which we sold in a series of transactions during the second quarter of 2010, our average net production was 17,608 BOE/d in the second quarter of 2010. As the sales occurred in the second quarter of 2010, our average net production for the first and second quarters of 2011 did not reflect any production from Texas.

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

Capital Expenditures

        We have developed an active capital expenditure program to take advantage of our extensive inventory of drilling prospects and other projects. Our current development, exploitation and exploration capital expenditure budget for 2011 is $200 million, of which approximately $133 million was expended in the first six months of 2011. We have budgeted approximately 70% or $140 million for Southern California and 30% or $60 million for the Sacramento Basin. Of the $140 million allocated to Southern California, approximately $100 million is scheduled to be deployed to onshore Monterey shale activities with the remainder going to activities at legacy Southern California fields. The aggregate levels of capital expenditures for 2011, 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 to date and the current outlook for the remainder of 2011 based on our current budget.

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

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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 completed the well early in the third quarter. We also performed four recompletions during the first half of the year. We plan to keep a rig drilling at West Montalvo for the remainder of the year and drill two to three offshore wells. The first of these wells was spud early in the third quarter.

        In the Sockeye field, we redrilled two inactive wells that target the Monterey shale formation during the second quarter and also replaced an electric submersible pump on another well; these activities are expected to increase production during the second half of the year. Our current 2011 capital expenditure budget contemplates minimal activity levels at Sockeye during the second half 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 three to six recompletions which we expect to begin during the third quarter. The work is expected to be completed early in the fourth quarter.

        In addition, our subsidiary Ellwood Pipeline, Inc. is pursuing the permits necessary to build a common carrier pipeline that would allow us to transport our oil from the South Ellwood field to refiners without the use of a barge or the marine terminal we currently use. A final environmental impact report for the project was released in July 2011 and we anticipate that approval hearings for the project will be held during the third quarter. While we believe the pipeline should be approved, the outcome of these hearings cannot be predicted.

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 advantageous. To date, our onshore Monterey shale acreage position totals approximately 244,000 gross and 168,000 net acres and is located primarily in three basins: Santa Maria, Salinas Valley and San Joaquin. An additional 60,000 gross and 46,000 net acres with Monterey shale production or potential are held by production.

        During the first six months of 2011 we spud seven new wells, including three horizontal wells, and set casing on eight wells (including wells spud last year). In total, since the beginning of 2010 through the second quarter of 2011, we have spud 19 wells (13 vertical and six horizontal), of which 16 have had casing set (11 vertical and five horizontal) and two wells, both vertical, were used as pilot holes for two horizontal wells. Subsequent to the end of the second quarter, one horizontal well has had casing set and one vertical well has been spud. 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 significant production as a result of our drilling. We currently have one drilling rig operating in the Sevier prospect where we recently spud a vertical well, our second well of the year in this prospect. We plan to keep a rig drilling in Sevier for the remainder of the year and spud three to four more wells there by year end. We have received data from the second and final phase of the 3D seismic shoot performed in the San Joaquin area and will analyze this data during the remainder of the year. We also plan to continue leasing throughout the year.

        We have designed the initial vertical wells to provide scientific information that we will use to evaluate the specific prospect area, as well as individual zones in the wellbore. Information developed

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from the analysis of cores from these vertical wells is used to correlate our petrophysical model with data from historical well logs in the area. Hydrocarbon test rates on the vertical wells have ranged from 20 BOE/d to more than 150 BOE/d, and all but one of the wells have tested with light oil (23 to 39 degree API). Through our evaluation process, we have identified certain prospect areas that we believe will be developed with vertical well completions. We believe the potential exists for additional areas to be identified as candidates for vertical drilling while horizontal wells could have greater potential for production in other areas. Our primary focus with respect to our initial wells is on using our experience with, and the data generated from, those wells to develop and refine drilling and completion techniques that will be successful in the formation and effective processes for the identification of productive intervals on a replicable basis.

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 six months of 2011, we spud 27 wells and performed 99 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 14 wells fractured during the first six 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 plan to drill seven additional wells along this trend by the end of the year.

        We have reduced our activity levels in the basin in 2011 as a result of depressed natural gas prices and our increased focus on our oil-based Monterey shale activities. Our current 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 $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 in order to reduce the variability of the prices we receive for our production and provide a minimum revenue stream. As of July 29, 2011 we had hedge contract floors covering 8,000 barrels of oil per day and 60 million cubic feet of natural gas per day. We have also secured hedge contracts for portions of our 2012 and 2013 production. All of our derivatives counterparties are members, or affiliates of members, of our revolving credit facility

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syndicate. 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, which are based on the NYMEX WTI ("WTI") crude price index, will expire at the end of the first quarter of 2012. Upon expiration, 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") (see "—Commodity Derivative Transactions").

        Expected Production.    In 2010, we began to emphasize our oil projects in Southern California relative to our natural gas projects in the Sacramento Basin. We believe that execution of our expected capital expenditure plan will result in a modest increase in average daily production volumes in 2011, relative to our 2010 results from our legacy assets. Although we have projected growth from our onshore Monterey shale project in 2011, we have not yet seen significant production from the project. In addition, we expect some delays in completing subsequent wells due to the current limited availability of field services. We therefore expect a smaller contribution to our full-year production from the onshore Monterey shale project than originally anticipated, though we continue to have positive long-term expectations related to the project. If the project is ultimately successful, we believe that it could result in significant production growth in subsequent years. 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, 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 $13.33 per BOE for the first six 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 our focus on oil projects, which tend to have higher operating costs than natural gas projects. Our expectations with respect to future expenses are subject to numerous risks and uncertainties, including those described and referenced in the preceding paragraph.

        Property and Production Taxes.    Property and production taxes of $0.93 per BOE for the first six months of 2011 were lower than our full year 2010 results of $1.01 per BOE. We expect our full year 2011 property and production taxes to be 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 increased slightly from $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), to $4.96 per BOE (excluding share-based compensation charges of $0.87 per BOE) in the first six months of 2011. Excluding share-based compensation charges, on a per BOE basis, we expect our G&A costs to be relatively flat in 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 six months of 2011 of $13.56 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.

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        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 June 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.

Results of Operations

        The following table reflects the components of our oil and natural gas production and sales prices and sets forth our operating revenues, costs and expenses on a BOE basis for the three and six months ended June 30, 2010 and 2011. This information reflects the actual historical results of our operations.

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

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(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 June 30, 2011 to Quarter Ended June 30, 2010

        Oil and Natural Gas Sales.    Oil and natural gas sales increased $17.4 million (25%) in the second quarter of 2011 to $85.9 million compared to $68.5 million in the second quarter of 2010. Sales in the second quarter of 2011 were primarily affected by higher oil prices compared to the second quarter of 2010, partially offset by lower oil production in the second quarter of 2011 as described below.

        Oil sales increased by $15.8 million (35%) in the second quarter of 2011 to $60.7 million compared to $44.9 million in the second quarter of 2010. Oil production decreased by 12%, with production of 619 MBbls in the second quarter of 2011 compared to 700 MBbls in the second quarter of 2010. The production decrease was partially due to the sales of our producing properties in Texas in the second quarter of 2010. Excluding production from the Texas properties, production decreased by 46 MBbls (7%) from 665 MBbls in the second quarter of 2010 to 619 MBbls in the second quarter of 2011. The decrease is primarily due to natural production decline from the Sockeye, South Ellwood and West Montalvo fields. Our average realized price for oil increased $29.41 per Bbl (44%) from $66.96 per Bbl in the second quarter of 2010 to $96.37 per Bbl for the second quarter of 2011.

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        Natural gas sales increased $1.6 million (7%) in the second quarter of 2011 to $25.2 million compared to $23.6 million in the second quarter of 2010. Natural gas production increased slightly (2%) in the second quarter of 2011, with production of 5,874 MMcf compared to 5,732 MMcf in the second 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 six months of 2011. Our average realized price for natural gas increased $0.17 per Mcf (4%) from $4.12 per Mcf in the second quarter of 2010 to $4.29 per Mcf in the second quarter of 2011.

        Other Revenues.    Other revenues decreased by $0.2 million (12%) to $1.4 million in the second quarter of 2011 from $1.6 million in the second 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 the revenues from those activities. The decrease in other revenues is the result of lower sub-charter activities in the second quarter of 2011 compared with the second quarter of 2010.

        Lease Operating Expenses.    Lease operating expenses ("LOE") decreased $1.6 million (7%) to $21.0 million in the second quarter of 2011 from $22.6 million in the second quarter of 2010. The decrease in LOE is partially due to the sales of our producing properties in Texas in the second quarter of 2010. Excluding the Texas properties, lease operating expenses decreased $0.8 million (4%) from $21.8 million in the second quarter of 2010 to $21.0 million in the second quarter of 2011. On a per unit basis, LOE decreased by $0.51 per BOE from $13.65 in the second quarter of 2010 to $13.14 in the second quarter of 2011. Excluding the Texas assets, LOE per BOE decreased from $13.63 per BOE in the second quarter of 2010 to $13.14 per BOE in the second quarter of 2011.

        Property and Production Taxes.    Property and production taxes remained constant at $1.4 million for both the second quarter of 2011 and the second quarter of 2010. On a per BOE basis, property and production taxes increased slightly from $0.82 per BOE in the second quarter of 2010 to $0.90 per BOE in the second quarter of 2011.

        Transportation Expenses.    Transportation expenses remained constant at $2.7 million for both the second quarter of 2011 and the second quarter of 2010. On a per BOE basis, transportation expenses also remained relatively consistent at $1.67 per BOE in the second quarter of 2011 compared to $1.61 per BOE in the second quarter of 2010. As described in "—Other Revenues", 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 increase on a per BOE basis is due to lower production in the second quarter of 2011.

        Depletion, Depreciation and Amortization (DD&A).    DD&A expense increased $3.0 million (16%) to $21.7 million in the second quarter of 2011 from $18.7 million in the second quarter of 2010. The increase is due to a higher depletion rate which resulted from a higher amortizable base coupled with lower proved oil and natural gas reserve volumes at the end of the second quarter of 2011 compared to the end of the second quarter of 2010. DD&A expense on a per unit basis increased by $2.27 per BOE from $11.32 per BOE for the second quarter of 2010 to $13.59 per BOE for the second quarter of 2011.

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

        G&A expenses decreased $2.0 million (18%) from $10.8 million in the second quarter of 2010 to $8.8 million in the second quarter of 2011. The decrease was primarily due to (i) one-time severance payments of $1.3 million related to the sale of our Texas properties and the related closure of our Texas operations in the second quarter of 2010 and (ii) higher capitalization in the second quarter of 2011 as a result of an increased focus on onshore Monterey shale activities. Excluding the effect of the non-cash share-based compensation expense and one-time severance charges, G&A expense decreased to $4.70 per BOE in the second quarter of 2011 from $5.10 per BOE in the second quarter of 2010.

        Interest Expense, Net.    Interest expense, net of interest income, increased $5.7 million (55%) from $10.3 million in the second quarter of 2010 to $16.0 million in the second 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 second quarter of 2010, averaged approximately 4.5% per annum during that period.

        Amortization of Deferred Loan Costs.    Amortization of deferred loan costs was $0.6 million in the second quarter of 2011 compared to $0.7 million in the second 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 second quarter of 2010, we recognized an unrealized interest rate derivative loss of $11.7 million and a realized interest rate derivative loss of $4.6 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):

        Realized commodity derivative gains or losses represent the difference between the strike prices in the contracts settled during the period and the ultimate settlement prices. The realized commodity derivative gains in the second quarter of 2011 and the same period in 2010 reflect the settlement of

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contracts at prices below the relevant strike prices. In addition, we unwound certain oil 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 June 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 both of the three month periods ended June 30, 2010 and June 30, 2011.

        Net Income (Loss).    Net income for the second quarter of 2011 was $19.0 million compared to net income of $3.7 million for the same period in 2010. The change between periods is the result of the items discussed above.

Comparison of Six Months Ended June 30, 2011 to Six Months Ended June 30, 2010

        Oil and Natural Gas Sales.    Oil and natural gas sales increased $13.8 million (9%) to $164.2 million for the six months ended June 30, 2011 from $150.4 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 $19.0 million (20%) for the first half of 2011 to $115.0 million compared to $96.0 million in the first half of 2010. Oil production decreased by 17%, with production of 1,227 MBbls in the first half of 2011 compared to 1,481 MBbls in the first half 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 142 MBbls (10%) from 1,369 MBbls in the first six months of 2010 to 1,227 MBbls in the first six months of 2011. The decrease is primarily due to natural production decline from the Sockeye, South Ellwood and West Montalvo fields. Our average realized price for oil increased $23.62 (35%) from $67.80 per Bbl in the first six months of 2010 to $91.42 per Bbl for the first six months of 2011.

        Natural gas sales decreased $5.3 million (10%) in the first half of 2011 to $49.2 million compared to $54.5 million in the first half of 2010. Natural gas production increased slightly (3%) with production of 11,846 MMcf in the first half of 2011 compared to 11,513 MMcf in the first half 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 six months of 2011. Our average realized price for natural gas decreased $0.57 per Mcf (12%) from $4.73 per Mcf in the first half of 2010 to $4.16 per Mcf for the first half of 2011.

        Other Revenues.    Other revenues decreased by $0.2 million (6%) to $2.2 million in the first half of 2011 from $2.4 million in the first half 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 the revenues

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from those activities. The decrease in other revenues is the result of lower sub-charter activities in the first six months of 2011 compared with the period in which the contract was effective during 2010.

        Lease Operating Expenses.    Lease operating expenses ("LOE") decreased $0.7 million (2%) to $42.7 million in the first half of 2011 from $43.4 million in the first half of 2010. Excluding the Texas properties, lease operating expenses increased $2.0 million (5%) from $40.7 million in the first half of 2010 to $42.7 million in the first half of 2011. The increase was primarily due to a reduction in oil inventory levels, which resulted in the recognition of the associated lifting costs in the income statement in the first six months of 2011. On a per unit basis, LOE increased by $0.55 per BOE from $12.78 in the first half of 2010 to $13.33 in the first half of 2011. Excluding the Texas assets, LOE per BOE increased from $12.60 per BOE in the first half of 2010 to $13.33 per BOE in the first half of 2011.

        Property and Production Taxes.    Property and production taxes decreased $0.6 million (16%) to $3.0 million in the first half of 2011 from $3.6 million in the first half of 2010. 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 $1.0 million (25%) to $4.7 million in the first half of 2011 from $3.7 million in the first half of 2010. On a per BOE basis, transportation expenses increased $0.35 per BOE, from $1.10 per BOE in the first half of 2010 to $1.45 per BOE in the first half of 2011. The increase is primarily due to a transportation contract which became effective April 2010, related to the time-charter of a double-hulled barge to transport oil produced from our South Ellwood field. Under that contract we pay a flat day rate, regardless of our usage of the barge, but have the ability to sub-charter the vessel when it is not in use transporting production from the South Ellwood field (see "—Other Revenues"). The increase in the first half of 2011 period compared to the same period in 2010 was the result of the transportation contract being in place for the full six months of the 2011 period compared to three months in the 2010 period.

        Depletion, Depreciation and Amortization (DD&A).    DD&A expense increased $4.7 million (12%) to $43.4 million in the first half of 2011 from $38.7 million in the first half of 2010. The increase is due to a higher depletion rate primarily due to lower proved oil and natural gas reserve volumes at the end of both the first and second quarters of 2011 compared to the end of the first and second quarters of 2010. DD&A expense on a per unit basis increased by $2.17 per BOE from $11.39 per BOE for the first half of 2010 to $13.56 per BOE for the first half of 2011.

        Accretion of Abandonment Liability.    Accretion expense remained relatively constant at $3.2 million in the first half of 2011 compared to $3.1 million in the first half of 2010.

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

        G&A expense decreased $1.5 million (8%) to $18.7 million in the first half of 2011 from $20.2 million in the first half of 2010. The overall decrease in G&A costs was primarily due to (i) one-time severance payments of $1.3 million related to the sale of our Texas properties and the

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related closure of our Texas operations and (ii) higher capitalization in the second quarter of 2011 as a result of an increased focus on onshore Monterey shale activities. Excluding the effect of the non-cash share-based compensation expense and one-time severance charges, G&A expense remained relatively constant at $4.96 per BOE in the first half of 2011 compared to $4.93 per BOE in the first half of 2010.

        Interest Expense, Net.    Interest expense, net of interest income, increased $8.3 million (40%) from $20.4 million in the first half of 2010 to $28.7 million in the first half of 2011. The increase was primarily the result 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 half of 2010, averaged approximately 4.5% per annum during that period.

        Amortization of Deferred Loan Costs.    Amortization of deferred loan costs was $1.1 million in the first half of 2011 compared to $1.4 million in the first half 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 half 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 half of 2010, we recognized an unrealized interest rate derivative loss of $16.7 million and a realized interest rate derivative loss of $9.1 million.

        Loss on Extinguishment of Debt.    We recognized a loss on extinguishment of debt in the first half 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):

        Realized commodity derivative gains or losses represent the difference between the strike prices in the contracts settled during the period and the ultimate settlement prices. The realized commodity derivative gains in both the first half of 2011 and the first half of 2010 reflect the settlement of contracts at prices below the relevant strike prices. In addition, we unwound certain oil 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

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and June 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 six month period ended June 30, 2011. The income tax benefit of $0.2 million for the six months ended June 30, 2010 relates to an increase in the estimated net operating loss carryback claim for the 2003 through 2005 tax years.

        Net Income (Loss).    Net loss for the first half of 2011 was $4.9 million compared to net income of $47.7 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

        Net cash provided by operating activities was $49.6 million in the first six months of 2011 compared with $55.1 million in the 2010 period. Cash flows from operating activities in the first six 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 $132.8 million in the first six months of 2011 compared with net cash provided of $5.2 million in the 2010 period. The primary investing activities in the first six months of 2011 were $131.8 million in capital expenditures on oil and natural gas properties related to our capital expenditure program. The primary investing activities in the first six months of 2010 were the receipt of $99.4 million in net cash proceeds from the sales of our Texas producing properties in the second quarter of 2010, offset by $90.7 million in capital expenditures on oil and natural gas properties related to our capital expenditure program.

        Net cash provided by financing activities was $81.3 million in the first six months of 2011 compared to net cash used of $58.5 million during the 2010 period. The primary financing activities in the first six months of 2011 were the two capital raising transactions we completed as described below in "—Capital Resources and Requirements". The primary financing activities in the first six months of 2010 were $31.9 million in net payments made on our revolving credit facility and $30.7 million of principal repayments on the second lien term loan, both of which were primarily funded by proceeds from the sales of our producing properties in Texas.

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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 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 $200 million, of which we have incurred approximately $133 million during the first half of 2011. We expect to fund our 2011 capital expenditures primarily with cash flow from operations, supplemented with borrowings under our revolving credit facility and cash on hand. 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.

        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

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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 July 29, 2011, there were no amounts drawn on our revolving credit facility.

        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 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.

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Off-Balance Sheet Arrangements

        At June 30, 2011, we had no existing off-balance sheet arrangements, as defined under SEC rules, that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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 June 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 based on the differential between the agreement price and the actual NYMEX WTI (oil) or NYMEX Henry Hub (natural gas) price.

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(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.

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        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 and hedge the effect of future changes to the WTI-Brent relationship. 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 June 30, 2011 are presented below:

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Portfolio of Derivative Transactions

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

Oil

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Natural Gas

        We enter into derivative contracts, primarily collars, swaps and option contracts, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. The objective of our hedging activities and the use of derivative financial instruments is to achieve more predictable cash flows. Our hedging activities seek to mitigate our exposure to price declines and allow us more flexibility to continue to execute our capital expenditure plan even if market prices decline. Our collar and swap contracts, however, prevent us from receiving the full advantage of increases in oil or natural gas prices above the maximum fixed amount specified in the hedge agreement. We do not enter into hedge positions for amounts greater than our expected production levels; however, if actual production is less than the amount we have hedged and the price of oil or natural gas exceeds a fixed price in a hedge contract, we will be required to make payments against which there are no offsetting sales of production. This could impact our liquidity and our ability to fund future capital expenditures. If we were unable to satisfy such a payment obligation, that default could result in a cross-default under our revolving credit agreement. In addition, we have incurred, and may incur in the future, substantial unrealized commodity derivative losses in connection with our hedging activities, although we do not expect such losses to have a material effect on our liquidity or our ability to fund expected capital expenditures.

        In addition, the use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. We generally have netting arrangements with our 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 our derivative contracts are also lenders, or

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affiliates of lenders, under our revolving credit facility. Collateral under the revolving credit facility supports our collateral obligations under our derivative contracts. Therefore, we are not required to post additional collateral when we are in a derivative liability position. Our revolving credit facility and our derivative contracts contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations.

        We have elected not to apply hedge accounting to any of our derivative transactions and consequently, we recognize 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.

        All derivative instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date. Changes in the fair value of derivatives are recorded in commodity derivative (gains) losses on the consolidated statement of operations. As of June 30, 2011, the fair value of our commodity derivatives was a net asset of $2.4 million.

Interest Rate Derivative Transactions

        We are subject to interest rate risk with respect to amounts borrowed from time to time under our revolving credit facility because those amounts bear interest at variable rates. Prior to the refinancing of our second lien term loan facility, we were similarly subject to interest rate risk with respect to amounts borrowed under that facility. Until that refinancing, we were party to interest rate swap transactions that limited our exposure to changes in interest rates with respect to $500.0 million of variable rate borrowings through May 2014. Pursuant to those transactions, we paid a fixed interest rate of 3.840% and received a floating interest rate based on the one-month LIBO rate. As a result, $500 million of our variable rate debt effectively bore interest at a fixed rate of approximately 7.8%. Contemporaneously with the refinancing of the second lien term loan facility, we settled our interest rate swaps for $38.1 million in February 2011.

        See notes to our condensed consolidated financial statements for a discussion of our long-term debt as of June 30, 2011.

Item 4.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

        Our management, with the participation of Timothy Marquez, our Chief Executive Officer, and Timothy Ficker, our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of June 30, 2011. Based on the evaluation, those officers believe that:

•

our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms; and



•

our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 was accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

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Internal Control Over Financial Reporting

        There has not been any change in our internal control over financial reporting that occurred during the quarterly period ended June 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1.    LEGAL PROCEEDINGS

The information set forth in Note 9 to the financial statements included in this report is incorporated by reference herein.

Item 1A.    RISK FACTORS

        In addition to the other information set forth in this report, you should carefully consider the factors discussed in "Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2010, which could materially affect our business, financial condition and/or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

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

Not Applicable

Item 3.    DEFAULTS UPON SENIOR SECURITIES

Not Applicable

Item 4.    REMOVED AND RESERVED

Not Applicable

Item 5.    OTHER INFORMATION

Not Applicable

Item 6.    EXHIBITS

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SIGNATURES

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

August 2, 2011

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