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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549



Form 10-Q

ý

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the quarterly period ended September 30, 2010oro

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934Commission File Number: 333-123711


Venoco, Inc.

Delaware(State or other jurisdiction of
incorporation or organization)

77-0323555(I.R.S. Employer
Identification Number)370 17th Street, Suite 3900
Denver, Colorado(Address of principal executive offices)

80202-1370(Zip Code)


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

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

Indicate
by check mark whether the registrant (1) has filed all reports required by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. YES ý    NO o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to
be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that
the registrant was required to submit and post such files). YES o    NO o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer o

Accelerated filer ý

Non-accelerated filer o (Do not check if a
smaller reporting company)

Smaller reporting company o


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

As of September 30, 2010, there were 55,656,200 shares of the issuer's common stock, par value $0.01 per share, issued and outstanding.



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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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



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VENOCO, INC.  Form 10-Q for the Quarterly Period Ended September 30, 2010        TABLE OF CONTENTS



PART I.

FINANCIAL INFORMATIONItem 1.

Financial Statements (Unaudited)


2Condensed Consolidated Balance Sheets at December 31, 2009 and September 30, 2010


2Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2009
and the Three and Nine Months Ended September 30, 2010


3Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended
September 30, 2009 and the Three and Nine Months Ended September 30, 2010


4Condensed Consolidated Statements of Changes in Stockholders' Equity for the Nine Months Ended September 30,
2010


5Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and the Nine Months
Ended September 30, 2010


6Notes to Condensed Consolidated Financial Statements


7Item 2.

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


32Item 3.

Quantitative and Qualitative Disclosures about Market Risk


48Item 4.

Controls and Procedures


52PART II.

OTHER INFORMATION


53Item 1.

Legal Proceedings


53Item 1A.

Risk Factors


53Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds


53Item 3.

Defaults upon Senior Securities


53Item 4.

Removed and Reserved


53Item 5.

Other Information


54Item 6.

Exhibits


54Signatures


55


1

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PART IFINANCIAL INFORMATION        VENOCO, INC. AND SUBSIDIARIES        CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)        (In thousands,
except shares and per share amounts)

December 31,
2009

September 30,
2010ASSETSCURRENT ASSETS:Cash and cash equivalents

$
419

$
10Accounts receivable, net of allowance for doubtful accounts of $900 and $700 at December 31, 2009 and September 30, 2010, respectively


33,853


32,585Inventories


6,139


5,915Other current assets


4,276


5,942Income taxes receivable


3,116


12,034Deferred income taxes


8,400


Commodity derivatives


34,611


48,536Total current assets


90,814


105,022PROPERTY, PLANT AND EQUIPMENT, AT COST:Oil and gas properties, full cost method of accountingProved


1,640,967


1,686,491Unproved


31,934


42,886Accumulated depletion


(1,073,664
)

(1,128,576
)Net oil and gas properties


599,237


600,801Other property and equipment, net of accumulated depreciation and amortization of $14,875 and $16,406 at December 31, 2009 and September 30, 2010,
respectively


20,193


19,208Net property, plant and equipment


619,430


620,009OTHER ASSETS:Commodity derivatives


18,720


32,085Deferred loan costs


7,908


6,444Other


2,671


2,645Total other assets


29,299


41,174TOTAL ASSETS

$
739,543

$
766,205LIABILITIES AND STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities

$
56,855

$
47,463Interest payable


4,885


9,466Commodity and interest derivatives


49,709


27,654Total current liabilities


111,449


84,583LONG-TERM DEBT


695,029


647,900COMMODITY AND INTEREST DERIVATIVES


15,076


34,058ASSET RETIREMENT OBLIGATIONS


92,485


94,476Total liabilities


914,039


861,017COMMITMENTS AND CONTINGENCIESSTOCKHOLDERS' EQUITY:Common stock, $.01 par value (200,000,000 shares authorized; 52,513,397 and 55,656,200 shares issued and outstanding at December 31, 2009 and
September 30, 2010, respectively)


525


557Additional paid-in capital


325,871


342,438Retained earnings (accumulated deficit)


(500,892
)

(437,807
)Total stockholders' equity


(174,496
)

(94,812
)TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
739,543

$
766,205


See notes to condensed consolidated financial statements.

2

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VENOCO, INC. AND SUBSIDIARIES        CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)        (In thousands, except per share amounts)

Three Months Ended
September 30,

Nine Months Ended
September 30,2009

2010

2009

2010REVENUES:Oil and natural gas sales

$
69,284

$
69,220

$
188,726

$
220,597Other


859


1,507


2,547


3,893Total revenues


70,143


70,727


191,273


224,490EXPENSES:Oil and natural gas production


28,015


22,449


80,280


69,466Transportation expense


1,144


3,065


2,954


7,753Depletion, depreciation and amortization


21,974


19,475


65,265


58,191Accretion of asset retirement obligations


1,429


1,518


4,174


4,649General and administrative, net of amounts capitalized


9,607


8,264


26,164


28,435Total expenses


62,169


54,771


178,837


168,494Income (loss) from operations


7,974


15,956


12,436


55,996FINANCING COSTS AND OTHER:Interest expense, net


9,327


10,117


30,282


30,539Amortization of deferred loan costs


751


499


2,224


1,855Interest rate derivative losses (gains), net


4,791


11,048


13,691


36,848Loss on extinguishment of debt








582


Commodity derivative losses (gains), net


7,577


(20,896
)

9,501


(75,931
)Total financing costs and other


22,446


768


56,280


(6,689
)Income (loss) before income taxes


(14,472
)

15,188


(43,844
)

62,685Income tax provision (benefit)


(9,200
)

(200
)

(4,300
)

(400
)Net income (loss)

$
(5,272
)
$
15,388

$
(39,544
)
$
63,085Earnings per common share:Basic

$
(0.10
)
$
0.28

$
(0.78
)
$
1.16Diluted

$
(0.10
)
$
0.28

$
(0.78
)
$
1.14Weighted average common shares outstanding:Basic


50,826


52,410


50,770


51,844Diluted


50,826


53,259


50,770


52,750


See
notes to condensed consolidated financial statements.

3

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VENOCO, INC. AND SUBSIDIARIES        CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)        (UNAUDITED)        (In thousands)

Three Months Ended
September 30,

Nine Months Ended
September 30,2009

2010

2009

2010Net income (loss)

$
(5,272
)
$
15,388

$
(39,544
)
$
63,085OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:Hedging activities:Reclassification adjustments for settled contracts


222





1,424


Other comprehensive income (loss)


222





1,424


Comprehensive income (loss)

$
(5,050
)
$
15,388

$
(38,120
)
$
63,085


See
notes to condensed consolidated financial statements.

4

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VENOCO, INC. AND SUBSIDIARIES        CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY        (UNAUDITED)        (In thousands)

Common Stock



Retained
Earnings
(Accumulated
Deficit)Additional
Paid-in
CapitalShares

Amount

TotalBALANCE AT DECEMBER 31, 2009


52,513

$
525

$
325,871

$
(500,892
)
$
(174,496
)Issuance of stock pursuant to stock incentive plans


1,538


16


10,693





10,693Issuance of restricted shares, net of cancellations


1,605


16


(16
)




Share-based compensation








5,890





5,890Net income (loss)











63,085


63,085BALANCE AT SEPTEMBER 30, 2010


55,656

$
557

$
342,438

$
(437,807
)
$
(94,812
)


See
notes to condensed consolidated financial statements.

5

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VENOCO, INC. AND SUBSIDIARIES        CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)        (In thousands)

Nine Months Ended
September 30,2009

2010CASH FLOWS FROM OPERATING ACTIVITIES:Net income (loss)

$
(39,544
)
$
63,085Adjustments to reconcile net income (loss) to net cash provided by operating activities:Depletion, depreciation and amortization


65,265


58,191Accretion of asset retirement obligations


4,174


4,649Deferred income tax provision (benefit)





8,400Share-based compensation


2,000


4,118Amortization of deferred loan costs


2,224


1,855Amortization of bond discounts and other non-cash interest


339


441Loss on extinguishment of debt


582


Unrealized interest rate swap derivative losses (gains)


(160
)

23,285Unrealized commodity derivative losses (gains) and amortization of premiums and other comprehensive loss


75,060


(52,062
)Changes in operating assets and liabilities:Accounts receivable


10,775


6,393Inventories


(2,492
)

(105
)Other current assets


(380
)

(1,776
)Income taxes receivable


(4,916
)

(8,918
)Other assets


(925
)

26Accounts payable and accrued liabilities


(11,921
)

(4,912
)Net premiums paid on derivative contracts


(10,382
)

(6,711
)Net cash provided by operating activities


89,699


95,959CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for oil and natural gas properties


(147,891
)

(152,353
)Acquisitions of oil and natural gas properties


(21,681
)

(2,645
)Expenditures for other property and equipment


(1,600
)

(2,331
)Proceeds from sale of oil and natural gas properties


197,653


98,103Net cash (used in) provided by investing activities


26,481


(59,226
)CASH FLOWS FROM FINANCING ACTIVITIES:Proceeds from long-term debt


107,156


105,000Principal payments on long-term debt


(219,167
)

(152,570
)Payments for deferred loan costs


(333
)

(281
)Proceeds from stock incentive plans and other


446


10,709Net cash (used in) provided by financing activities


(111,898
)

(37,142
)Net increase (decrease) in cash and cash equivalents


4,282


(409
)Cash and cash equivalents, beginning of period


191


419Cash and cash equivalents, end of period

$
4,473

$
10Supplemental Disclosure of Cash Flow InformationCash paid for interest

$
30,460

$
25,583Cash paid for income taxes

$
616

$
250Supplemental Disclosure of Noncash ActivitiesAccrued capital expenditures at period end

$
11,224

$
18,325Increase (decrease) in accrued capital expenditures

$
(18,979
)
$
3,090


See notes to condensed consolidated financial statements.

6

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VENOCO, INC. AND SUBSIDIARIES        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS        (UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES

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

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

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

Income TaxesThe Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate
to
its year-to-date income or loss, except for discrete items. Income taxes for discrete items are computed and recorded in the period in which the specific transaction occurs.
The Company incurred losses before income taxes in 2008 and 2009. These losses were a key consideration that led the Company to provide a valuation allowance against its net deferred tax assets at
December 31, 2009 and September 30, 2010 since it could not conclude that it is more likely than not that the net deferred tax assets will be fully realized on future tax returns. As
long as the Company concludes that it will continue to have a need for a full valuation allowance against its net deferred tax assets, the Company likely will not have any income tax expense or
benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims or for state income taxes. The income tax
benefit for the nine months ended September 30, 2009 relates to a reduction of prior year current income tax expense ($6.6 million benefit), partially offset by federal AMT (primarily
related to the Hastings transaction) and state income tax expense of $2.3 million. The income tax benefit for the nine months ended September 30, 2010, relates to an increase in the
estimated net operating loss carryback claims for the 2003 through 2005 tax years and a reduction in the amount owed for prior year state income taxes.

7

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

The
Company's federal income tax returns for the 2003, 2004 and 2005 tax years have been examined by the U.S. Internal Revenue Service ("IRS"). In the second quarter of 2010, the IRS
adjusted the Company's taxable income for the tax years 2005 through 2008 for disallowed deductions from the 2003 and 2004 examinations (no adjustments resulted from the 2005 examination). As part of
that process
with the IRS, the Company carried back net operating losses ("NOL") to tax years 2003 through 2005, which resulted in federal tax refunds of $8.6 million. Although the IRS did not examine the
2006 through 2008 tax years, it did conduct an analysis of significant transactions and other significant income and deductions for those years in connection with the Company's NOL carryback claims.
The 2007 through 2009 tax years remain open to examination by the IRS.

During
the third quarter of 2010, the California Department of Revenue completed an examination of the Company's 2003 and 2004 California income tax returns. No adjustments resulted from
this examination other than adjustments related to the finalization of the federal examinations discussed above, which the Company had previously provided for in its liability for uncertain state tax
positions. The 2006 through 2009 tax years remain open to examination by the various state jurisdictions.

Due
to the finalization of the 2003, 2004 and 2005 federal examinations, the NOL carryback claims filed with the IRS and the finalization of the 2003 and 2004 California examinations,
the Company believes that it has no liability for uncertain tax positions.

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.

8

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

Three Months
Ended
September 30,

Nine Months
Ended
September 30,2009

2010

2009

2010Dilutive





4,843





4,884Anti-dilutive


5,054


148


4,917


511


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

Three Months Ended
September 30,

Nine Months Ended
September 30,2009

2010

2009

2010Net income (loss)

$
(5,272
)
$
15,388

$
(39,544
)
$
63,085Allocation of net income to unvested restricted stock





(746
)




(2,982
)Net income (loss) allocated to common stock

$
(5,272
)
$
14,642

$
(39,544
)
$
60,103Basic weighted average common shares outstanding


50,826


52,410


50,770


51,844Add: dilutive effect of stock options





849





906Diluted weighted average common shares outstanding


50,826


53,259


50,770


52,750Basic earnings per common share

$
(0.10
)
$
0.28

$
(0.78
)
$
1.16Diluted earnings per common share

$
(0.10
)
$
0.28

$
(0.78
)
$
1.14




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

2. ACQUISITIONS AND SALES OF PROPERTIES

Sales of Texas Assets.In April 2010, the Company signed certain Purchase and Sale Agreements ("PSAs") to divest its producing
properties in Texas
("Texas Sales") for $107.5 million (before closing adjustments), each with an effective date of January 1, 2010. The PSAs covered the Company's interests in the Manvel field, the
Company's overriding royalty interest in the Hastings Complex and its other oil and natural gas producing properties in the Texas Gulf Coast. The sales closed in a series of transactions in the second
quarter of 2010 and involved multiple purchasers, including Denbury

9

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

2. ACQUISITIONS AND SALES OF PROPERTIES (Continued)

Resources, Inc.
("Denbury"), which purchased the overriding royalty interest in the Hastings Complex. The aggregate net proceeds from the transactions were $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 applied the
proceeds from the Texas Sales to reduce the capitalized cost of its oil and natural gas properties. As a result of the Texas Sales, the Company no longer has any interests in producing oil and natural
gas properties in Texas. The Company did, however, retain its 22.3% reversionary working interest in the Hastings Complex.

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

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

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

3. LONG-TERM DEBT

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

December 31,
2009

September 30,
2010Revolving credit agreement due January 2013

$
57,860

$
41,000Second lien term loan due May 2014


494,485


463,77611.50% senior notes due October 2017


142,684


143,124Total long-term debt


695,029


647,900Less: current portion of long-term debt





Long-term debt, net of current portion

$
695,029

$
647,900


Revolving credit facility.In December 2009, the Company entered into the Third Amended and Restated Credit Agreement related to its
$300 million revolving credit facility with a syndicate of banks

10

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

3. LONG-TERM DEBT (Continued)

("revolving
credit facility"). The facility has a maturity date of January 15, 2013 and the borrowing base (currently established at $125 million) is subject to redetermination twice
each year, and may be redetermined at other times at the Company's request or at the request of the lenders. The facility is secured by a first priority lien on substantially all of the Company's oil
and natural gas properties and other assets, including the equity interests in all of the Company's subsidiaries, and is unconditionally guaranteed by each of the Company's operating subsidiaries
other than Ellwood Pipeline, Inc. The collateral also secures the Company's obligations to hedging counterparties that are also lenders, or affiliates of lenders, under the facility. Loans
designated as Base Rate Loans under the facility bear interest at a floating rate equal to (i) the greater of (x) the Bank of Montreal's announced base rate, (y) the overnight
federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.5%, plus (ii) an applicable margin ranging from 0.75% to 1.50%, based upon utilization. Loans designated as
LIBO Rate Loans under the facility bear interest at (i) LIBOR plus (ii) an applicable margin ranging from 2.25% to 3.00%, based upon utilization. A commitment fee of 0.50% per annum is
payable with respect to unused borrowing availability under the facility. The agreement governing the facility contains customary representations, warranties, events of default, indemnities and
covenants, including operational covenants that restrict the Company's ability to incur indebtedness and financial covenants that require the Company to maintain specified ratios of current assets to
current liabilities and debt to EBITDA.

The
borrowing base under the revolving credit facility has been allocated at various percentages to a syndicate of ten banks. Certain of the institutions included in the syndicate have
received support from governmental agencies in connection with events in the credit markets. As of October 29, 2010, the
Company had available borrowing capacity of $101.0 million under the facility, net of the outstanding balance of $20.0 million and $4.0 million in outstanding letters of credit.

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

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

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

3. LONG-TERM DEBT (Continued)

required
to repay $30.7 million of the outstanding principal balance from the proceeds of the Texas Sales in the second quarter of 2010.

Senior notes.In October 2009, the Company issued $150.0 million of 11.50% senior notes due October 2017 at a price of 95.03% of
par. The
notes are senior unsecured obligations and contain covenants that, among other things, limit the Company's ability to make investments, incur additional debt, issue preferred stock, pay dividends,
repurchase its stock, create liens or sell assets. The senior notes pay interest semi-annually in arrears on April 1 and October 1 of each year. The Company may redeem the
senior notes prior to October 1, 2013 at a "make-whole price" defined in the indenture. Beginning October 1, 2013, the Company may redeem the notes at a redemption price
equal to 105.75% of the principal amount and declining to 100% by October 1, 2016.

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

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

The
Company has paid and received 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 September 30, 2010, the balance of unamortized net derivative premiums paid was $23.1 million, of which $5.7 million,
$10.1 million, $6.6 million and $0.7 million will be amortized in the remainder of 2010, 2011, 2012 and 2013, respectively.

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

Three Months Ended
September 30,

Nine Months Ended
September 30,2009

2010

2009

2010Realized commodity derivative (gains) losses

$
(16,675
)
$
(10,863
)
$
(63,748
)
$
(23,869
)Amortization of commodity derivative premiums


5,999


5,657


16,662


16,972Unrealized commodity derivative (gains) losses for changes in fair value:


18,253


(15,690
)

56,587


(69,034
)Commodity derivative (gains) losses

$
7,577

$
(20,896
)
$
9,501

$
(75,931
)


As
of September 30, 2010, the Company had entered into swap, collar and option agreements related to its oil and natural gas production. The aggregate economic effects of those
agreements are summarized below. Location and quality differentials attributable to the Company's properties are not included in the following prices. The agreements provide for monthly settlement
based on the

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

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

Oil (NYMEX WTI)

Natural Gas
(NYMEX Henry Hub)Barrels/day

Weighted Avg.
Prices per Bbl

MMBtu/day

Weighted Avg.
Prices per MMBtuOctober 1 - December 31, 2010:Swaps


1,000

$
66.75





Swap arrangements(1)








11,000

$
7.00Collars(1)


5,150

$
60.00/$86.53


6,900

$
7.50/$7.00Collar arrangements(1)(2)








10,000

$
6.00/$7.00Puts


1,850

$
40.00


31,000

$
6.00January 1 - December 31, 2011:Collars(1)


5,000

$
50.00/$100.00


12,000

$
5.75/$7.12Puts(1)


2,000

$
50.00


48,000

$
6.31January 1 - December 31, 2012:Collars(1)


3,000

$
60.00/$121.10





Puts(1)








37,300

$
5.81January 1 - December 31, 2013:Collars(1)








20,000

$
5.00/$7.02


---

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

Floating Index

MMBtu/Day

Weighted
Avg. Basis
Differential to
NYMEX HH
(per MMBtu)Basis Swaps:October 1 - December 31, 2010

PG&E Citygate


51,618

$
0.14January 1 - December 31, 2011

PG&E Citygate


57,224

$
0.11January 1 - December 31, 2012

PG&E Citygate


47,400

$
0.28


In
October 2010, the Company settled natural gas puts on 12,000 MMBtu per day at $7.50 per MMBtu and settled a $5.75 by $7.12 per MMBtu natural gas collar on 12,000 MMBtu per day. Both
settled contracts were effective for the period from January 1, 2011 through December 31, 2011. The Company received approximately $19.1 million in proceeds from the settlements.
The Company also entered into natural gas swaps at $4.44 per MMBtu on 24,000 MMBtu per day for the period from January 1, 2011 through December 31, 2011.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

Interest Rate Swap.The Company has entered into interest rate swap transactions to lock in its interest cost on $500.0 million of
variable
rate borrowings through May 2014. The Company pays a fixed interest rate of 3.840% and receives a floating interest rate based on the 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 bears interest at a fixed rate of approximately 7.8%. The Company did not designate the interest
rate swap as a hedge.

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

Three Months Ended
September 30,

Nine Months Ended
September 30,2009

2010

2009

2010Realized interest rate derivative (gains) losses

$
4,781

$
4,495

$
13,851

$
13,563Unrealized interest rate derivative (gains) losses


10


6,553


(160
)

23,285Interest rate derivative (gains) losses, net

$
4,791

$
11,048

$
13,691

$
36,848


Fair Value of Derivative Instruments.The estimated fair values of derivatives included in the consolidated balance sheets at
December 31,
2009 and September 30, 2010 are summarized below. The net fair value of the Company's derivatives increased by $30.4 million from a net liability of $11.5 million at
December 31, 2009 to a net asset of $18.9 million at September 30, 2010, primarily due to changes in futures prices for oil and natural gas, which are used in the calculation of
the fair value of commodity derivatives and changes to the Company's commodity derivative portfolio during the period. 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

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

December 31, 2009

September 30, 2010Current AssetsCommodity derivatives:Oil derivative contracts

$
12,461

$
3,919Gas derivative contracts


22,150


44,61734,611


48,536Other AssetsCommodity derivatives:Oil derivative contracts


296


247Gas derivative contracts


18,424


31,83818,720


32,085Current LiabilitiesCommodity and interest derivatives:Oil derivative contracts


(25,690
)

(9,533
)Gas derivative contracts


(7,787
)

(833
)Interest rate derivative contracts


(16,232
)

(17,288
)(49,709
)

(27,654
)Commodity and interest derivatives:Oil derivative contracts





(1,644
)Gas derivative contracts


(4,968
)

(77
)Interest rate derivative contracts


(10,108
)

(32,337
)(15,076
)

(34,058
)Net derivative (liability) asset

$
(11,454
)
$
18,909


5. FAIR VALUE MEASUREMENTS

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

5. FAIR VALUE MEASUREMENTS (Continued)

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

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

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

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

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

Level 1

Level 2

Level 3

Fair Value
as of
September 30,
2010Assets (Liabilities):Commodity derivative contracts

$


$
80,621

$


$
80,621Commodity derivative contracts





(12,087
)




(12,087
)Interest rate derivative contracts





(49,625
)




(49,625
)


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

Commodity Derivative Contracts.The Company's commodity derivative instruments consist primarily of swaps, collars and option contracts
for oil and
natural gas. The Company values the derivative contracts using industry standard models, based on an income approach, which 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.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

5. FAIR VALUE MEASUREMENTS (Continued)

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

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

December 31, 2009

September 30, 2010Carrying
Value

Estimated
Fair Value

Carrying
Amount

Estimated
Fair ValueRevolving credit agreement

$
57,860

$
57,860

$
41,000

$
41,000Second lien term loan


494,485


445,037


463,776


435,94911.50% senior notes


142,684


142,545


143,124


159,168


6. ASSET RETIREMENT OBLIGATIONS

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

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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 nine months ended September 30, 2009 and 2010 (in thousands):

Nine Months
Ended
September 30, 2009

Nine Months
Ended
September 30, 2010Asset retirement obligations at beginning of period

$
80,579

$
92,985Revisions of estimated liabilities


332


710Liabilities incurred/acquired


6,742


4,366Liabilities settled


(564
)

(1,942
)Disposition of properties


(2,993
)

(5,292
)Accretion expense


4,174


4,649Asset retirement obligations at end of period


88,270


95,476Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)


(1,075
)

(1,000
)Long-term asset retirement obligations

$
87,195

$
94,476


7. CAPITAL STOCK

The Company has 61.3 million shares of common stock issued or reserved for issuance at September 30, 2010. At September 30, 2010, the Company has 55.7 million
common shares issued and outstanding, of which 2.6 million shares are restricted stock granted under the Company's 2005 stock incentive plan. At September 30, 2010, the Company had
approximately 1.7 million options outstanding and 3.3 million shares available to be issued pursuant to awards under its stock incentive plans, including the 2008 Employee Stock Purchase
Plan.

In
October 2010, the Company filed a prospectus supplement to its existing registration statement on Form S-3, under which it may from time to time sell an aggregate
of up to $75 million of its common stock through an "at-the-market" program. No shares have been sold under the program.

8. SHARE-BASED PAYMENTS

The Company has granted options to directors, certain employees and officers of the Company, other than its CEO, under its 2000 and 2005 Stock Plans (the "Stock Plans"). As of
September 30, 2010, there
are a total of 1,683,498 options outstanding with a weighted average exercise price of $10.88 ($6.00 to $20.00). The options vest over a four year period, with 20% vesting on the grant date and 20%
vesting on each subsequent anniversary of the grant date. The options typically have a maximum life of 10 years. The options will generally vest upon a change in control of the Company.
Unexercised options expire when an option holder elects to terminate employment or if the Company terminates the holder's employment for misconduct. If the Company terminates a holder's employment
other than for misconduct, unvested options generally terminate and the holder has a limited period of time within which to exercise vested options, unless the award agreement provides otherwise.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

8. SHARE-BASED PAYMENTS (Continued)

In
2009 the Company implemented a non-compensatory Employee Stock Purchase Plan (the "ESPP"), authorizing 1.5 million shares of common stock to be issued under the
ESPP. Participation in the ESPP is open to all employees, other than executive officers, who meet limited qualifications. Under the terms of the ESPP, employees are able to purchase Company stock at a
5% discount as determined by the fair market value of the Company's stock on the last trading day of each purchase period. Individual employees are limited to $25,000 of common stock purchased in any
calendar year.

As
of September 30, 2010, there were a total of 2,616,153 shares of restricted stock outstanding under the Company's 2005 stock incentive plan, including 859,517 shares granted to
its CEO. The restricted shares generally have a requisite service period of four years. The grant date fair value of restricted stock subject to service conditions only is determined by the Company's
closing stock price on the day prior to the date of grant. The vesting of 1,475,029 shares is also subject to market conditions based on the Company's total shareholder return in comparison to peer
group companies for each calendar year. The weighted-average fair value of the restricted shares subject to market conditions was derived using a Monte Carlo technique. The weighted average fair value
of 954,065 awards with market conditions granted in February 2010 was estimated to be $10.65 per share. The estimated grant date fair values of restricted share awards are recognized as expense over
the requisite service periods.

As
of September 30, 2010, there was $0.3 million of total unrecognized compensation cost related to stock options, which is expected to be amortized over a weighted-average
period of 0.5 years, and $18.0 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.

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

Three Months
Ended
September 30,

Nine Months
Ended
September 30,2009

2010

2009

2010General and administrative expense

$
910

$
1,660

$
2,940

$
5,020Oil and natural gas production expense


190


290


510


870Total share-based compensation costs


1,100


1,950


3,450


5,890Less: share-based compensation costs capitalized


(294
)

(563
)

(1,450
)

(1,772
)Share-based compensation expensed

$
806

$
1,387

$
2,000

$
4,118


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

8. SHARE-BASED PAYMENTS (Continued)

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

Options

Weighted
Average
Exercise
PriceOutstanding, start of period


3,301,903

$
8.92Granted




$
Exercised


(1,516,655
)
$
6.87Cancelled


(101,750
)
$
8.23Outstanding, end of period


1,683,498

$
10.88Exercisable, end of period


1,573,098

$
10.46


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

Shares

Weighted
Average
Grant Date
Fair ValueNon-vested, start of period


1,594,156

$
7.20Granted


1,843,435

$
11.75Vested


(582,758
)
$
9.09Forfeited


(238,680
)
$
10.72Non-vested, end of period


2,616,153

$
9.66


9. CONTINGENCIES



Between June 2003 and April 2005, six lawsuits were filed against the Company and certain other energy companies in Los Angeles County
Superior Court by persons who attended Beverly Hills High School or who were or are citizens of Beverly Hills/Century City or visitors to that area during the time period running from the 1930s to
date. There are approximately 1,000 plaintiffs (including plaintiffs in two related lawsuits in which the Company has not been named) who claimed to be suffering from various forms of cancer or other
illnesses, fear they may suffer from such maladies in the future, or are related to persons who have suffered from cancer or other illnesses. Plaintiffs alleged that exposure to substances in the air,
soil and water that originated from either oil-field or other operations in the area were the cause of the cancers and other maladies. The Company has owned an oil and natural gas facility
adjacent to the school since 1995. For the majority of the plaintiffs, their alleged exposures occurred before the Company acquired the facility. All cases were consolidated before one judge. Twelve
"representative" plaintiffs were selected to have their cases tried first, while all of the other plaintiffs' cases were stayed. In November 2006, the judge entered summary judgment in favor of all
defendants in the test cases, including the Company. The judge dismissed all claims by the test case

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

9. CONTINGENCIES (Continued)

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 for events occurring
prior to 1995, which the Company is disputing. The Company cannot predict the cost of these indemnity claims at the present time.

One
of the Company's insurers currently is paying for the defense of these lawsuits under a reservation of its rights. Three other insurers that provided insurance coverage to the
Company (the "Declining Insurers") took the position that they were not required to provide coverage for losses arising out of, or to defend against, the lawsuits because of a pollution exclusion
contained in their policies. In February 2006, the Company filed a declaratory relief action against the Declining Insurers in Santa Barbara County Superior Court seeking a determination that those
insurers have a duty to defend the Company in the lawsuits. Two of the three Declining Insurers settled with the Company. The third Declining Insurer disputed the Company's position and in November
2007 the Santa Barbara Court granted that insurer's motion for summary judgment, in part on the basis that the pollution exclusion provision in the policy did not require that insurer to provide a
defense for the Company. That decision was upheld on appeal. The Company has no reason to believe that the insurer currently providing defense of these actions will cease providing such defense. If it
does, and the Company is unsuccessful in enforcing its rights in any subsequent litigation, the Company may be required to bear the costs of the defense, and those costs may be material. If it
ultimately is determined that the pollution exclusion or another exclusion contained in one or more of the Company's policies applies, the Company will not have the protection of those policies with
respect to any damages or settlement costs ultimately incurred in the lawsuits.

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



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

22

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

9. CONTINGENCIES (Continued)



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

23

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedASSETSCURRENT ASSETS:Cash and cash equivalents

$
418

$
1

$


$


$
419Accounts receivable


29,453


3,939


461





33,853Inventories


5,813


326








6,139Other current assets


4,276











4,276Income taxes receivable


3,116











3,116Deferred income taxes


8,400











8,400Commodity derivatives


34,611











34,611TOTAL CURRENT ASSETS


86,087


4,266


461





90,814PROPERTY, PLANT & EQUIPMENT, NET


697,270


(80,955
)

3,115





619,430COMMODITY DERIVATIVES


18,720











18,720INVESTMENTS IN AFFILIATES


512,074








(512,074
)

OTHER


10,235


344








10,579TOTAL ASSETS

$
1,324,386

$
(76,345
)
$
3,576

$
(512,074
)
$
739,543LIABILITIES AND STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities

$
52,129

$
4,726

$


$


$
56,855Interest payable


4,885











4,885Commodity and interest derivatives


49,709











49,709TOTAL CURRENT LIABILITIES:


106,723


4,726








111,449LONG-TERM DEBT


695,029











695,029COMMODITY AND INTEREST DERIVATIVES


15,076











15,076ASSET RETIREMENT OBLIGATIONS


84,925


6,638


922





92,485INTERCOMPANY PAYABLES (RECEIVABLES)


597,129


(549,473
)

(47,656
)




TOTAL LIABILITIES


1,498,882


(538,109
)

(46,734
)




914,039TOTAL STOCKHOLDERS' EQUITY


(174,496
)

461,764


50,310


(512,074
)

(174,496
)TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
1,324,386

$
(76,345
)
$
3,576

$
(512,074
)
$
739,543


24

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedASSETSCURRENT ASSETS:Cash and cash equivalents

$
10

$


$


$


$
10Accounts receivable


32,059


107


419





32,585Inventories


5,915











5,915Other current assets


5,942











5,942Income tax receivable


12,034











12,034Commodity derivatives


48,536











48,536TOTAL CURRENT ASSETS


104,496


107


419





105,022PROPERTY, PLANT & EQUIPMENT, NET


799,376


(185,513
)

6,146





620,009COMMODITY DERIVATIVES


32,085











32,085INVESTMENTS IN AFFILIATES


519,381








(519,381
)

OTHER


8,744


345








9,089TOTAL ASSETS

$
1,464,082

$
(185,061
)
$
6,565

$
(519,381
)
$
766,205LIABILITIES AND STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities

$
46,986

$
477

$


$


$
47,463Interest payable


9,466











9,466Commodity and interest derivatives


27,654











27,654TOTAL CURRENT LIABILITIES:


84,106


477








84,583LONG-TERM DEBT


647,900











647,900COMMODITY AND INTEREST DERIVATIVES


34,058











34,058ASSET RETIREMENT OBLIGATIONS


91,929


1,574


973





94,476INTERCOMPANY PAYABLES (RECEIVABLES)


700,901


(651,718
)

(49,183
)




TOTAL LIABILITIES


1,558,894


(649,667
)

(48,210
)




861,017TOTAL STOCKHOLDERS' EQUITY


(94,812
)

464,606


54,775


(519,381
)

(94,812
)TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
1,464,082

$
(185,061
)
$
6,565

$
(519,381
)
$
766,205


25

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Table of Contents

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 SEPTEMBER 30, 2009 (Unaudited)  (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
62,035

$
7,249

$


$


$
69,284Other


688


64


1,484


(1,377
)

859Total revenues


62,723


7,313


1,484


(1,377
)

70,143EXPENSES:Oil and natural gas production


25,257


2,086


672





28,015Transportation expense


2,425


16





(1,297
)

1,144Depletion, depreciation and amortization


20,259


1,672


43





21,974Accretion of asset retirement obligations


1,308


108


13





1,429General and administrative, net of amounts capitalized


8,787


820


80


(80
)

9,607Total expenses


58,036


4,702


808


(1,377
)

62,169Income (loss) from operations


4,687


2,611


676





7,974FINANCING COSTS AND OTHER:Interest expense, net


10,267


(1
)

(939
)




9,327Amortization of deferred loan costs


751











751Interest rate derivative losses (gains), net


4,791











4,791Commodity derivative losses (gains), net


7,577











7,577Total financing costs and other


23,386


(1
)

(939
)




22,446Equity in subsidiary income


2,621








(2,621
)

Income (loss) before income taxes


(16,078
)

2,612


1,615


(2,621
)

(14,472
)Income tax provision (benefit)


(10,806
)

992


614





(9,200
)Net income (loss)

$
(5,272
)
$
1,620

$
1,001

$
(2,621
)
$
(5,272
)


26

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Table of Contents

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 SEPTEMBER 30, 2010 (Unaudited)  (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
69,318

$
(98
)
$


$


$
69,220Other


1,358


64


1,291


(1,206
)

1,507Total revenues


70,676


(34
)

1,291


(1,206
)

70,727EXPENSES:Oil and natural gas production


21,852


(11
)

608





22,449Transportation expense


4,184


1





(1,120
)

3,065Depletion, depreciation and amortization


19,310


28


137





19,475Accretion of asset retirement obligations


1,471


30


17





1,518General and administrative, net of amounts capitalized


8,191


44


115


(86
)

8,264Total expenses


55,008


92


877


(1,206
)

54,771Income (loss) from operations


15,668


(126
)

414





15,956FINANCING COSTS AND OTHER:Interest expense, net


11,088





(971
)




10,117Amortization of deferred loan costs


499











499Interest rate derivative losses (gains), net


11,048











11,048Commodity derivative losses (gains), net


(20,896
)










(20,896
)Total financing costs and other


1,739





(971
)




768Equity in subsidiary income


781








(781
)

Income (loss) before income taxes


14,710


(126
)

1,385


(781
)

15,188Income tax provision (benefit)


(678
)

(48
)

526





(200
)Net income (loss)

$
15,388

$
(78
)
$
859

$
(781
)
$
15,388


27

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS  NINE MONTHS ENDED SEPTEMBER 30, 2009 (Unaudited)  (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
165,290

$
23,436

$


$


$
188,726Other


2,156


91


4,293


(3,993
)

2,547Total revenues


167,446


23,527


4,293


(3,993
)

191,273EXPENSES:Oil and natural gas production


68,834


9,716


1,730





80,280Transportation expense


6,651


55





(3,752
)

2,954Depletion, depreciation and amortization


59,154


6,021


90





65,265Accretion of asset retirement obligations


3,790


344


40





4,174General and administrative, net of amounts capitalized


24,119


2,045


241


(241
)

26,164Total expenses


162,548


18,181


2,101


(3,993
)

178,837Income (loss) from operations


4,898


5,346


2,192





12,436FINANCING COSTS AND OTHER:Interest expense, net


33,018


(5
)

(2,731
)




30,282Amortization of deferred loan costs


2,224











2,224Interest rate derivative losses (gains), net


13,691











13,691Loss on extinguishment of debt


582











582Commodity derivative losses (gains), net


9,501











9,501Total financing costs and other


59,016


(5
)

(2,731
)




56,280Equity in subsidiary income


6,370








(6,370
)

Income (loss) before income taxes


(47,748
)

5,351


4,923


(6,370
)

(43,844
)Income tax provision (benefit)


(8,204
)

2,033


1,871





(4,300
)Net income (loss)

$
(39,544
)
$
3,318

$
3,052

$
(6,370
)
$
(39,544
)


28

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
210,370

$
10,227

$


$


$
220,597Other


3,574


67


3,801


(3,549
)

3,893Total revenues


213,944


10,294


3,801


(3,549
)

224,490EXPENSES:Oil and natural gas production


64,941


3,143


1,382





69,466Transportation expense


11,030


13





(3,290
)

7,753Depletion, depreciation and amortization


55,957


1,831


403





58,191Accretion of asset retirement obligations


4,369


229


51





4,649General and administrative, net of amounts capitalized


26,124


2,236


334


(259
)

28,435Total expenses


162,421


7,452


2,170


(3,549
)

168,494Income (loss) from operations


51,523


2,842


1,631





55,996FINANCING COSTS AND OTHER:Interest expense, net


33,374


(1
)

(2,834
)




30,539Amortization of deferred loan costs


1,855











1,855Interest rate derivative losses (gains), net


36,848











36,848Commodity derivative losses (gains), net


(75,931
)










(75,931
)Total financing costs and other


(3,854
)

(1
)

(2,834
)




(6,689
)Equity in subsidiary income


4,531








(4,531
)

Income (loss) before income taxes


59,908


2,843


4,465


(4,531
)

62,685Income tax provision (benefit)


(3,177
)

1,080


1,697





(400
)Net income (loss)

$
63,085

$
1,763

$
2,768

$
(4,531
)
$
63,085


29

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedCASH FLOWS FROM OPERATING ACTIVITIES:Net cash provided by (used in) operating activities

$
63,998

$
20,722

$
4,979

$


$
89,699CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for oil and natural gas properties


(134,547
)

(11,893
)

(1,451
)




(147,891
)Acquisitions of oil and natural gas properties


(21,681
)










(21,681
)Expenditures for property and equipment and other


(2,107
)

507








(1,600
)Proceeds from sale of oil and natural gas properties





197,653








197,653Net cash provided by (used in) investing activities


(158,335
)

186,267


(1,451
)




26,481CASH FLOWS FROM FINANCING ACTIVITIES:Net proceeds from (repayments of) intercompany borrowings


210,517


(206,989
)

(3,528
)




Proceeds from long-term debt


107,156











107,156Principal payments on long-term debt


(219,167
)










(219,167
)Payments for deferred loan costs


(333
)










(333
)Proceeds from stock incentive plans and other


446











446Net cash provided by (used in) financing activities


98,619


(206,989
)

(3,528
)




(111,898
)Net increase (decrease) in cash and cash equivalents


4,282











4,282Cash and cash equivalents, beginning of period


190


1








191Cash and cash equivalents, end of period

$
4,472

$
1

$


$


$
4,473


30

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedCASH FLOWS FROM OPERATING ACTIVITIES:Net cash provided by (used in) operating activities

$
86,187

$
4,811

$
4,961

$


$
95,959CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for oil and natural gas properties


(147,977
)

(942
)

(3,434
)




(152,353
)Acquisitions of oil and natural gas properties


(2,645
)










(2,645
)Expenditures for property and equipment and other


(2,331
)










(2,331
)Proceeds from sale of oil and natural gas properties





98,103








98,103Net cash provided by (used in) investing activities


(152,953
)

97,161


(3,434
)




(59,226
)CASH FLOWS FROM FINANCING ACTIVITIES:Net proceeds from (repayments of) intercompany borrowings


103,500


(101,973
)

(1,527
)




Proceeds from long-term debt


105,000











105,000Principal payments on long-term debt


(152,570
)










(152,570
)Payments for deferred loan costs


(281
)










(281
)Proceeds from stock incentive plans and other


10,709











10,709Net cash provided by (used in) financing activities


66,358


(101,973
)

(1,527
)




(37,142
)Net increase (decrease) in cash and cash equivalents


(408
)

(1
)







(409
)Cash and cash equivalents, beginning of period


418


1








419Cash and cash equivalents, end of period

$
10

$


$


$


$
10


31

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Table of Contents

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

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

Overview

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural
gas properties. Our strategy is to grow through exploration, exploitation and development projects we believe have the potential to add significant reserves on a cost-effective basis and
through selective acquisitions of underdeveloped properties. Our average net production was 18,087 BOE/d in the third quarter of 2010, compared to 20,264 BOE/d in the third quarter of 2009 and 18,190
BOE/d in the second quarter of 2010. Excluding production from our producing properties in Texas, which we sold in a series of transactions during the second quarter of 2010, our average net
production was 18,087 BOE/d in the third quarter of 2010, compared to 18,705 BOE/d in the third quarter of 2009 and 17,608 BOE/d in the second quarter of 2010.

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

Capital Expenditures

We have developed an active capital expenditure program to take advantage of our extensive inventory of drilling prospects and other
projects. Our development, exploitation and exploration capital expenditure budget for 2010 is $220 million, of which approximately $158.0 million was expended in the first nine months
of 2010. We expect to spend approximately 49% of the budgeted amount on projects in the Sacramento Basin, 23% in our legacy Southern California fields, and 28% on onshore Monterey shale projects in
Southern California. Our recently announced 2011 development, exploitation and exploration capital expenditure budget is $200 million, of which approximately 50% is expected to be deployed for
onshore Monterey shale activities in Southern California, 30% to the Sacramento Basin, and the remaining 20% to activities at legacy Southern California fields. The aggregate levels of capital
expenditures for the remainder of 2010 and 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 deployed. Accordingly, the actual levels of capital expenditures and the allocation of those
expenditures may vary materially from our estimates. The following summarizes certain significant aspects of our 2010 capital spending program and the outlook for 2011:

Southern CaliforniaExploitation and Development

In the West Montalvo field, we have pursued an aggressive workover, recompletion and return to production program since acquiring the
field in May 2007 that has resulted in significant production gains. The field has not been fully delineated offshore or fully developed onshore and we continue to evaluate our drilling results and
refine our development program for the coming years. To date in 2010, our principal activities in the field have been the completion of two wells that were spud toward the end of 2009. We do not plan
any major activities in the field for the remainder of 2010, but our 2011 capital expenditure budget includes plans to drill two wells in the field.

32

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Table of Contents

In
the Sockeye field, we completed a hydraulic fracture of the E-8 well during the first quarter, and also completed a dual completion well that produces from the Monterey
shale formation and injects into the Lower Topanga formation, increasing the sweep of the waterflood in that zone. A planned redrill of an inactive well that targets the Monterey shale formation was
delayed as a result of a drilling moratorium imposed by the Secretary of the U.S. Department of the Interior. Wells drilled from Platform Gail are no longer subject to a moratorium and we plan to
proceed with the redrill in the fourth quarter of 2010. Our 2011 capital expenditure budget contemplates minimal activity levels at Sockeye next year.

At
the South Ellwood field, we performed six recompletions during the first half of the year, but have minimal drilling-related activities planned for the remainder of 2010. 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 in order to begin drilling those
locations in 2011. Our 2011 capital expenditure budget includes plans to drill one of our proved undeveloped locations and perform six recompletions at South Ellwood.

In
addition, our subsidiary Ellwood Pipeline, Inc. is pursuing the permits necessary to build a common carrier pipeline that would allow us to transport our oil from the South
Ellwood field to refiners without the use of a barge or the marine terminal we currently use. We anticipate that approval hearings for the project will be held during the first half of 2011. While we
believe the pipeline should be approved, the outcome of these hearings cannot be predicted. Pending completion of the pipeline, we expect to primarily use a double-hulled barge to transport oil
production from the field, although we will use an older, single-hulled barge while modifications are made to the double-hulled barge necessary to address permitting requirements. We expect those
modifications to be completed late in the fourth quarter of 2010. Beginning January 1, 2011, we will be required to use the double-hulled barge exclusively.

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

Sacramento BasinExploitation and Development

In the Sacramento Basin, we continue to pursue our infill drilling program in the greater Grimes and Willows fields. We expect to drill
approximately 100 wells in 2010 and perform approximately 225 recompletions. During the first nine months of 2010, we spud 74 wells and performed 160 recompletions.

We
continue to test and evaluate potential downspacing opportunities in the basin as well as new methods of improving productivity and reducing drilling costs. We also continue to pursue
our hydraulic fracturing program in the basin. We plan to fracture 12 wells in 2010, of which 11 were fractured in the first nine months of the year.

We
plan to reduce our focus on the basin in 2011 as a result of depressed natural gas prices and our increased focus on our oil-based Monterey shale activities. Our 2011
capital expenditure budget for the basin includes approximately 40 development wells, 220 recompletions, and 20 fracs. We anticipate the activity levels contemplated in our 2011 budget will result in
average daily production in 2011 that is flat to slightly lower compared to expected 2010 average daily production. Production from the basin in the beginning of 2011 is expected to be relatively flat
with the fourth quarter of 2010, then decline throughout the year as a result of the lower activity in 2011. We would expect to return to a focus on growth in the basin when natural gas prices
improve.

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TexasExploitation and Development

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

Onshore Monterey Shale Activities

In 2006, we began actively leasing onshore acreage in Southern California targeting the Monterey shale, a Miocene age strata. Our
leasing has focused on areas where we believe the Monterey shale will produce light, sweet oil, and where the quality and depth of the Monterey shale is expected to be advantageous. Approximately 28%
of our 2010 development, exploitation and exploration budget, or $62 million, is devoted to activities targeting the onshore Monterey shale formation. The budgeted expenditures include drilling
eleven gross wells, aggressively adding to our acreage position, and completing the first phase of, what we believe is, California's largest 3D seismic shoot. To date, our onshore Monterey shale
acreage position is approximately 162,000 gross and 120,000 net acres. An additional 60,000 gross and 50,000 net acres with Monterey shale production or potential are held by production.

We
spud eight onshore Monterey shale wells during the first nine months of the year, including six vertical evaluation wells and two horizontal development wells. We spud two more wells
in October, our third horizontal and our seventh vertical. We expect to spud our fourth horizontal well by the end of the year, bringing the total gross number of wells spud in 2010 to 11 (seven
vertical and four horizontal). Of the six vertical evaluation wells spud through nine months, three are in various stages of testing, one has been temporarily abandoned and will be evaluated as a
water disposal well, one was used after evaluation as a pilot hole for our first horizontal development well, and one reached total depth in October. The initial vertical wells are designed to provide
scientific information which we will use to evaluate the specific prospect area, as well as individual zones in the wellbore that are prospective for drilling horizontal wells. Information developed
from cutting cores in these vertical wells and analysis of those cores will be used to correlate our petrophysical model with data from historical well logs in the area. We expect the testing and
evaluation process to last several months for each test well.

Our
first horizontal well was drilled in the San Joaquin Valley during the third quarter and tested with a very high water cut and is uneconomic. Our second horizontal well, in the Santa
Maria Basin, was spud in September and reached total depth in early October. The well has been completed and we expect to begin testing in early November. Our third horizontal well is also in the
Santa Maria Basin and was spud in October. The fourth horizontal well will spud later in the fourth quarter in the Salinas Valley. We currently have two drilling rigs working our onshore Monterey
shale play, both of which are capable of drilling horizontal wells, and we are working to secure a third rig in order to execute our
2011 capital expenditure program. Our 2011 capital expenditure budget includes plans to drill a total of 30 wells including eight vertical evaluation wells and 22 horizontal development wells. We also
plan to complete the second and final phase of our 3D seismic shoot during the first half of 2011 and to continue leasing throughout the year.

Acquisitions and Divestitures

Sale of Texas Assets.We sold our producing assets in Texas in a series of transactions that were completed in the second quarter of
2010 to multiple
purchasers for aggregate net proceeds of $98.1 million (after closing adjustments and related expenses). We used the proceeds to repay $66.9 million of principal on the revolving credit
facility and $30.7 million of principal on the second lien term loan. We retained our 22.3% reversionary working interest in the Hastings Complex. The Texas properties sold comprised 7.2% of
our proved reserves at December 31, 2009 or 7.1 MMBOE and contributed approximately 620 BOE/d to our production during the first nine months of 2010.

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

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

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

Trends Affecting our Results of Operations

Oil and Natural Gas Prices.Historically, prices received for our oil and natural gas production have been volatile and unpredictable,
and that
volatility is expected to continue. Changes in the market prices for oil and natural gas directly impact many aspects of our business, including our financial condition, revenues, results of
operations, liquidity, rate of growth, the carrying value of our oil and natural gas properties and borrowing capacity under our revolving credit facility, all of which depend in part upon those
prices. 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 October 29, 2010 we had hedge
contract floors covering approximately 96% and 87% of our 2010 and 2011 annual production guidance, respectively. We have also begun to secure hedge contracts for our 2012 and 2013 production. All of
our derivatives counterparties are members, or affiliates of members, of our revolving credit facility syndicate. See "Quantitative and Qualitative Disclosures About Market RiskCommodity
Derivative Transactions" for further details concerning our hedging activities.

Expected Production.We expect our 2010 average daily production volumes to be approximately 18,600 BOE/d. Excluding production from
our producing
properties in Texas, which we sold in a series of transactions during the second quarter of 2010, our 2010 average daily production volumes are expected to be approximately 18,100 BOE/d. During 2010,
we began to emphasize our oil projects in Southern California relative to our natural gas projects in the Sacramento Basin. We plan to continue this strategy in 2011, with approximately 50% of our
planned capital expenditures allocated to our onshore Monterey shale program in Southern California, and an additional 20% allocated to our legacy Southern California fields. We expect that the
execution of our capital expenditure plan will result in a modest increase in average daily production volumes in 2011 relative to 2010. We expect our onshore Monterey shale project to contribute a
relatively small percentage of our overall production in 2011. However, we expect production from that project to offset declines from our legacy Southern California assets and to provide the modest
production growth we anticipate next year. If successful, we believe that the project 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, 2009.

Production Expenses.Production expenses consist of lease operating expenses ("LOE") and production and property taxes. LOE per BOE of
$12.67 for the
first nine months of 2010 is consistent with our full year 2009 results of $12.65 per BOE. We expect our LOE per BOE rate to increase slightly during the fourth quarter. In 2011, we expect our LOE per
BOE to increase slightly relative to 2010. Production and property taxes per BOE decreased to $1.05 per BOE for the first nine months of 2010 from $1.35 per BOE for the full year 2009. For the full
year 2010, we expect production/property taxes to decrease slightly on a per BOE basis compared to our 2009 results. We expect 2011 production/property taxes to increase slightly on a per BOE basis
compared to our 2010 results. Our

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expectations
with respect to future expenses are subject to numerous risks and uncertainties, including those described and referenced in the preceding paragraph.

General and Administrative Expenses.General and administrative expenses increased slightly from $4.63 per BOE for the full year 2009
(excluding
share-based compensation charges of $0.28 per BOE), to $4.73 per BOE (excluding share-based compensation charges of $0.64 per BOE and one-time charges of $0.25 per BOE for severance
payments resulting from the sale of our Texas producing properties) in the first nine months of 2010. Excluding share-based compensation charges and one-time severance charges, on a per
BOE basis, we expect our 2010 G&A costs to remain relatively constant for the remainder of the year. 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 production expenses, our expectations with respect to G&A costs are subject to numerous risks and uncertainties.

Depreciation, Depletion and Amortization (DD&A).DD&A for the first nine months of 2010 of $11.49 per BOE was flat with full
year 2009 DD&A of $11.46
per BOE. We expect our full year 2010 DD&A expenses to increase slightly on a per BOE basis compared to our 2009 results. We expect our 2011 DD&A to increase modestly on a per BOE basis compared to
our full year 2010 results. As with production and G&A expenses, our expectations with respect to DD&A expenses are subject to numerous risks and uncertainties.

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

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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 nine months ended September 30, 2009 and 2010. This information reflects the actual historical results of our operations. No pro
forma adjustments have been made for acquisitions and divestitures of oil and gas properties, which will affect the comparability of the data below.

Three Months Ended
September 30,

Nine Months Ended
September 30,2009

2010

2009

2010Production Volume:Oil (MBbls)(1)


811


682


2,593


2,163Natural gas (MMcf)


6,320


5,892


18,518


17,405MBOE


1,864


1,664


5,679


5,064Daily Average Production Volume:Oil (Bbls/d)


8,815


7,413


9,498


7,923Natural gas (Mcf/d)


68,696


64,043


67,832


63,755BOE/d


20,264


18,087


20,803


18,549Oil Price per Bbl Produced (in dollars):Realized price

$
58.09

$
66.35

$
46.80

$
67.78Realized commodity derivative gain (loss)


(4.66
)

(1.28
)

1.90


(1.40
)Net realized price

$
53.43

$
65.07

$
48.70

$
66.38Natural Gas Price per Mcf (in dollars):Realized price

$
3.17

$
3.93

$
3.59

$
4.46Realized commodity derivative gain (loss)


3.24


1.99


2.76


1.55Net realized price

$
6.41

$
5.92

$
6.35

$
6.01Expense per BOE:Lease operating expenses(2)

$
13.55

$
12.44

$
12.59

$
12.67Production and property taxes(2)


1.48


1.05


1.55


1.05Transportation expenses


0.61


1.84


0.52


1.53Depreciation, depletion and amortization


11.79


11.70


11.49


11.49General and administrative expense(3)


5.15


4.97


4.61


5.62Interest expense


5.00


6.08


5.33


6.03


---

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

Oil and Natural Gas Sales.Oil and natural gas sales remained relatively flat at $69.2 million for the quarter ended
September 30, 2010
and $69.3 million for the same period in 2009. Sales in the third quarter of 2010 were affected by an increase in realized oil and natural gas prices compared to the third quarter of 2009, but
this increase was offset by decreases in production as described below.

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Oil
sales decreased by $3.2 million (6%) in the third quarter of 2010 to $46.0 million compared to $49.2 million in the third quarter of 2009. Oil production
decreased by 16%, with production of 682 MBbls in the third quarter of 2010 compared to 811 MBbls in the third quarter of 2009. The production decrease was primarily due to the sales of our producing
properties in Texas which occurred in multiple closings throughout the second quarter of 2010. The Texas properties contributed 88 MBbls during the third quarter of 2009 compared to zero in third
quarter of 2010. Excluding production from the Texas properties, production decreased by 41 MBbls (6%) from 723 MBbls in the third quarter of 2009 to 682 MBbls in the third quarter of 2010. This
decrease is primarily due to (i) the natural decline of production at the Sockeye field and (ii) reduced production at the Dos Cuadras field as a result of certain wells being taken
offline due to operational difficulties. Our average realized price for oil increased $8.26 (14%) from $58.09 per Bbl in the third quarter of 2009 to $66.35 per Bbl for the third quarter of 2010.

Natural
gas sales increased $3.2 million (16%) in the third quarter of 2010 to $23.2 million compared to $20.0 million in the third quarter of 2009. Natural gas
production decreased 7%, with production of 5,892 MMcf in the third quarter of 2010 compared to 6,320 MMcf in the third quarter of 2009. The decrease was due primarily to the sales of our producing
properties in Texas which occurred during the second quarter of 2010. The Texas properties contributed 332 MMcf during the third quarter of 2009 compared to zero in the third quarter of 2010.
Excluding Texas properties, production decreased by 96
MMcf (2%) from 5,988 MMcf in the third quarter of 2009 compared to 5,892 MMcf in the third quarter of 2010. The slight decrease in production is primarily due to lower drilling and recompletion
activity in the Sacramento Basin in the latter half of 2009 and the natural decline of production from wells in the basin. Our average realized price for natural gas increased $0.76 per Mcf (24%) from
$3.17 per Mcf in the third quarter of 2009 to $3.93 per Mcf in the third quarter of 2010.

Other Revenues.Other revenues increased by $0.6 million (75%) to $1.5 million in the third quarter of 2010 from
$0.9 million in
the third quarter of 2009. The increase is primarily due to a contract that became effective April 2010, related to the double-hulled barge that transports oil produced at our South Ellwood field (see
"Transportation Expenses"). The contract allows us to sub-charter the barge and retain the revenues from those activities. The
increase in other revenues is the result of sub-charter activities in the third quarter of 2010.

Production Expenses.Production expenses, which consist of lease operating expenses ("LOE") and production/property taxes, decreased
$5.6 million (20%) to $22.4 million in the third quarter of 2010 from $28.0 million in the third quarter of 2009. The decrease was due primarily to the sales of our producing
properties in Texas which occurred throughout the second quarter of 2010. Production expenses attributable to the Texas properties were $3.6 million in the third quarter of 2009 and zero in the
third quarter of 2010. Excluding the Texas properties, production expenses decreased $1.9 million (8%) from $24.4 million in the third quarter of 2009 to $22.4 million in the
third quarter of 2010. The decrease was primarily due to (i) annual maintenance costs incurred at Platform Holly in the third quarter of 2009 and (ii) decreases in supplemental property
taxes incurred in the third quarter of 2010 compared to the third quarter of 2009 resulting from lower gas prices and lower assessed mineral rights valuations for drilling and recompletion activities.
On a per unit basis, LOE decreased to $12.44 per BOE in the third quarter of 2010 from $13.55 per BOE in the same period in 2009. Excluding the Texas properties, LOE per BOE decreased from $12.88 per
BOE in the third quarter of 2009 to $12.44 per BOE in the third quarter of 2010, which resulted from the lower production expenses incurred, as described above, partially offset by the decrease in
production levels in the third quarter of 2010.

Transportation Expenses.Transportation expenses increased $2.0 million (168%) to $3.1 million in the third quarter of 2010
from
$1.1 million in the third quarter of 2009. On a per BOE basis, transportation expenses increased $1.23 per BOE, from $0.61 per BOE in the third quarter of 2009 to $1.84 per BOE in the third
quarter of 2010. The increase is primarily due to the contract described in"Other Revenues", related to the time-charter of a
double-hulled barge to transport oil produced

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from
our South Ellwood field. Under that contract we pay a flat day rate, regardless of our usage of the barge, but have the ability to sub-charter the vessel when not in use transporting
production from the South Ellwood field (see "Other Revenues"). We also incurred additional transportation costs from the use of a
single-hulled barge during the transition period to the double-hulled barge. We expect that our transportation costs will be higher until the transition to the double-hulled barge is complete, which
is expected to occur late in the fourth quarter of 2010.

Depletion, Depreciation and Amortization (DD&A).DD&A expense decreased $2.5 million (11%) to $19.5 million in the
third quarter of
2010 from $22.0 million in the third quarter of 2009. The decrease is related to (i) a lower amortizable base in the third quarter of 2010 resulting from the application of the net
proceeds from the sales of our Texas producing properties and (ii) lower production in the third quarter 2010 compared to the third quarter of 2009. DD&A expense on a per unit basis remained
relatively flat at $11.70 per BOE for the third quarter of 2010 compared to $11.79 per BOE in the third quarter of 2009.

Accretion of Abandonment Liability.Accretion expense increased $0.1 million (6%) to $1.5 million in the third quarter of
2010 from
$1.4 million in the third quarter of 2009. The increase is primarily due to accretion from new wells drilled and completed in 2009 and the first nine months of 2010, partially offset by the
reduction in accretion resulting from the sale of our Texas properties in the second quarter of 2010.

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

Three Months Ended
September 30,2009

2010Share-based compensation costs

$
910

$
1,660Other general and administrative costs


14,370


11,770General and administrative costs capitalized


(5,673
)

(5,166
)General and administrative expense

$
9,607

$
8,264


G&A
expense decreased $1.3 million (14%) to $8.3 million in the third quarter of 2010 from $9.6 million in the third quarter of 2009. The overall decrease in G&A
costs was primarily due to a lower employee bonus accrual in the third quarter of 2010 compared to the third quarter of 2009, partially offset by non-cash share-based compensation expense
of $1.1 million (net of amount capitalized) charged to G&A in the third quarter of 2010 compared to $0.6 million (net of amount capitalized) in the third quarter of 2009. We issued
annual restricted stock awards in the first quarter of both 2010 and 2009. The fair value of the awards issued in the 2010 period was significantly greater than the grants in the 2009 period due to
the increase in our stock price that occurred between the periods, which contributed to the increase in non-cash share-based compensation expense. Excluding the effect of the
non-cash share-based compensation expense, G&A expense decreased to $4.31 per BOE in the third quarter of 2010 from $4.82 per BOE in the third quarter of 2009.

Interest Expense, Net.Interest expense, net of interest income, increased $0.8 million (8%) from $9.3 million in the third
quarter of
2009 to $10.1 million in the third quarter of 2010. The increase was primarily the result of higher interest costs related to the 11.50% senior notes outstanding in the third quarter of 2010
compared to the interest costs related to the 8.75% senior notes outstanding during the third quarter of 2009. The increase was partially offset by lower interest costs related to the second lien term
loan in the third quarter of 2010 resulting from principal reductions funded by the proceeds of the Texas sales.

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Amortization of Deferred Loan Costs.Amortization of deferred loan costs was $0.5 million in the third quarter of 2010 compared to
$0.8 million in the third quarter of 2009. The costs incurred relate to our loan agreements, which are amortized over the estimated lives of the agreements.

Interest Rate Derivative (Gains) Losses, Net.Changes in the fair value of our interest rate swap derivative instruments resulted in
unrealized
losses of $6.6 million in the third quarter of 2010 and nil in the 2009 period. Unrealized interest rate (gains) losses represent the change in the fair value of our interest rate derivative
contracts from period to period based on estimated future interest rates at the end of the reporting period. Realized interest rate swap losses were $4.5 million in the third quarter of 2010
compared to realized losses of $4.8 million in the third quarter of 2009.

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

Three Months Ended
September 30,2009

2010Realized commodity derivative (gains) losses

$
(16,675
)
$
(10,863
)Amortization of commodity derivative premiums


5,999


5,657Unrealized commodity derivative (gains) losses for changes in fair value


18,253


(15,690
)Commodity derivative (gains) losses

$
7,577

$
(20,896
)


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

Income Tax Expense (Benefit).We incurred losses before income taxes in both 2008 and 2009. These losses were a key consideration that
led us to
provide a valuation allowance against our net deferred tax assets at December 31, 2009 and September 30, 2010 since we could not conclude that it is more likely than not that the net
deferred tax assets will be fully realized. As long as we continue to conclude that we have a need for a full valuation allowance against our net deferred tax assets, we likely will not have any
income tax expense or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims, or for state income
taxes. The income tax benefit we recorded for the three months ended September 30, 2009 reflects a reduction of prior year current tax expense (a $6.6 million benefit) and federal AMT
and state income tax benefit of $2.6 million related to lower current earnings. The income tax benefit of $0.2 million that we recorded for the three months ended September 30,
2010 relates to a reduction of prior year state income taxes.

Net Income (Loss).Net income for the third quarter of 2010 was $15.4 million compared to net loss of $5.3 million for the
same period
in 2009. The change between periods is the result of the items discussed above.

Comparison of Nine Months Ended September 30, 2010 to Nine Months Ended September 30, 2009

Oil and Natural Gas Sales.Oil and natural gas sales increased $31.9 million (17%) to $220.6 million for the nine months
ended
September 30, 2010 from $188.7 million for the same period in 2009. The increase was due to increases in realized oil and natural gas prices, partially offset by a decrease in production
as described below.

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Oil
sales increased by $20.7 million (17%) for the first nine months of 2010 to $142.9 million compared to $122.2 million in the first nine months of 2009. Oil
production decreased by 17%, with production of 2,163 MBbls in the first nine months of 2010 compared to 2,593 MBbls in the first nine months of 2009. The production decrease was primarily due to the
sale of the Hastings Complex in early February 2009 and the sales of our remaining producing properties in Texas in the second quarter of 2010. The Texas properties (including Hastings) contributed
354 MBbls during the first nine months of 2009 compared to 112 MBbls in the first nine months of 2010. Excluding production from the Texas properties, production decreased by 188 MBbls (8%) from 2,239
MBbls in the first nine months of 2009 to 2,051 MBbls in the first nine months of 2010. This decrease is primarily due to (i) the natural decline of production at the Sockeye field and
(ii) reduced production at the Dos Cuadras field as a result of certain wells being taken offline due to operational difficulties. Our average realized price for oil increased $20.98 (45%) from
$46.80 per Bbl in the first nine months of 2009 to $67.78 per Bbl for the first nine months of 2010.

Natural
gas sales increased $11.2 million (17%) in the first nine months of 2010 to $77.7 million compared to $66.5 million in the first nine months of 2009. Natural
gas production decreased 6%, with
production of 17,405 MMcf in the first nine months of 2010 compared to 18,518 MMcf in the first nine months of 2009. The decrease was due in large part to the sales of our producing properties in
Texas which occurred during the second quarter of 2010. The Texas properties contributed 1,133 MMcf during the first nine months of 2009 compared to 341 MMcf in the first nine months of 2010.
Excluding production from the Texas properties, production decreased slightly by 321 MMcf (2%) from 17,385 MMcf in the first nine months of 2009 to 17,064 MMcf in the first nine months of 2010. The
slight decrease in production is due to lower drilling and recompletion activity in the Sacramento Basin in the latter part of 2009 and natural decline of production from wells in the basin. Our
average realized price for natural gas increased $0.87 per Mcf (24%) from $3.59 per Mcf in the first nine months of 2009 to $4.46 per Mcf for the first nine months of 2010.

Other Revenues.Other revenues increased by $1.4 million (53%) to $3.9 million in the first nine months of 2010 from
$2.5 million in the first nine months of 2009. The increase is primarily due to a contract that became effective in April 2010, related to the double-hulled barge that transports oil produced
at our South Ellwood field (see "Transportation Expenses"). The contract allows us to sub-charter the barge and retain the
revenues from those activities. The increase in other revenues is the result of sub-charter activities in the first nine months of 2010.

Production Expenses.Production expenses, which consist of lease operating expenses ("LOE") and production/property taxes, decreased
$10.8 million (13%) to $69.5 million in the first nine months of 2010 from $80.3 million in the first nine months of 2009. The decrease was primarily due to the sale of the
Hastings Complex in early February 2009 and the sale of our remaining Texas properties in the second quarter of 2010. Production expenses attributable to the Texas properties (including Hastings) were
$11.1 million in the first nine months of 2009 and $3.4 million in the first nine months of 2010. Excluding the Texas properties, production expenses decreased by $3.1 million
(5%) from $69.2 million in the first nine months of 2009 to $66.1 million in the first nine months of 2010. The decrease was primarily due to lower supplemental property taxes incurred
in 2010 as compared to 2009 resulting from lower gas prices and lower assessed mineral rights valuations for drilling and recompletion activities. On a per unit basis, LOE increased slightly from
$12.59 per BOE in the first nine months of 2009 to $12.67 per BOE in the first nine months of 2010. Excluding the Texas assets, LOE per BOE increased from $12.06 per BOE in the first nine months of
2009 to $12.55 per BOE in the first nine months of 2010. The increase on a per BOE basis is the result of decreased production levels in the first nine months of 2010 compared to the first nine months
of 2009.

Transportation Expenses.Transportation expenses increased $4.8 million (162%) to $7.8 million in the first nine months of
2010 from
$3.0 million in the first nine months of 2009. On a per BOE basis, transportation expenses increased $1.01 per BOE, from $0.52 per BOE in the first nine months of 2009

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to
$1.53 per BOE in the first nine months of 2010. The increase is primarily due to the contract described in"Other Revenues", related to
the time-charter of a double-hulled barge to transport oil produced from our South Ellwood field. Under that contract we pay a flat day rate, regardless of our usage of the barge, but have
the ability to sub-charter the vessel when it is not in use transporting production from the South Ellwood field (see "Other
Revenues"). We also incurred additional transportation costs from the use of a single-hulled barge during the transition period to the double-hulled barge. We expect that our
transportation costs will be higher until the transition to the double-hulled barge is complete, which is expected to occur late in the fourth quarter of 2010. Additionally, transportation expense for
the first nine months of 2009 includes demurrage reimbursements related to the single-hulled barge, which reduced our overall transportation expense for the 2009 period.

Depletion, Depreciation and Amortization (DD&A).DD&A expense decreased $7.1 million (11%) to $58.2 million in the
first nine months of
2010 from $65.3 million in the first nine months of 2009. The decrease is related to (i) a lower amortizable base in the second and third quarters of 2010 resulting from the application
of the net proceeds from the sale of our Texas producing properties, (ii) lower production in the first nine months of 2010 compared to the first nine months of 2009 and (iii) increases
(on a comparable basis) in our 2009 year-end and 2010 reserves. DD&A expense on a per unit basis remained constant at $11.49 per BOE for the first nine months of 2010 and the first nine months
of 2009.

Accretion of Abandonment Liability.Accretion expense increased $0.4 million (11%) to $4.6 million in the first nine months of
2010
from $4.2 million in the first nine months of 2009. The increase is primarily due to accretion from new wells drilled and completed in 2009 and the first nine months of 2010.

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

Nine Months Ended September 30,2009

2010Share-based compensation costs

$
2,940

$
5,020One-time severance costs





1,254Other general and administrative costs


42,249


39,208General and administrative costs capitalized


(19,025
)

(17,047
)General and administrative expense

$
26,164

$
28,435


G&A
expense increased $2.2 million (9%) to $28.4 million in the first nine months of 2010 from $26.2 million in the first nine months of 2009. The overall increase
in G&A costs was primarily due to increases resulting from: (i) G&A costs capitalized in the first nine months of 2010 being lower than the amount capitalized in the first nine months of 2009
due to lower levels of drilling activity in the first quarter of 2010, (ii) one-time severance payments of $1.3 million in 2010 related to the sale of our Texas properties
and the related closure of our Texas operations and (iii) non-cash share-based compensation expense of $3.2 million (net of amount capitalized) charged to G&A in the first
nine months of 2010 compared to $1.5 million (net of amount capitalized) in the first nine months of 2009, partially offset by lower other general and administrative costs resulting from the
closing of our Texas office and other G&A decreases. We issued annual restricted stock awards in the first quarter of both 2010 and 2009. The fair value of the awards issued in the 2010 period was
significantly greater than the grants in the 2009 period due to the increase in our stock price between the periods, which contributed to the increase in non-cash share-based compensation
expense. Excluding the effect of the non-cash share-based compensation expense and one-time severance charges, G&A expense increased to $4.73 per BOE in the first nine months
of 2010 from $4.34 per BOE in the first nine months of 2009. The increase on a per unit basis is primarily the result of lower production levels in the first nine months of 2010 compared with the
first nine months of 2009.

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Interest Expense, Net.Interest expense, net of interest income, remained relatively constant at $30.5 million in the first nine
months of
2010 compared to $30.3 million in the first nine months of 2009.

Amortization of Deferred Loan Costs.Amortization of deferred loan costs was $1.9 million in the first nine months of 2010
compared to
$2.2 million in the first nine months of 2009. The costs incurred relate to our loan agreements, which are amortized over the estimated lives of the agreements.

Interest Rate Derivative (Gains) Losses, Net.Changes in the fair value of our interest rate swap derivative instruments resulted in
unrealized
losses of $23.3 million in the first nine months of 2010 and unrealized gains of $0.2 million in the 2009 period. Unrealized interest rate (gains) losses represent the change in the fair
value of our interest rate derivative contracts from period to period based on estimated future interest rates at the end of the reporting period. Realized interest rate swap losses were
$13.6 million in the first nine months of 2010 and $13.9 million in the 2009 period.

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

Nine Months Ended
September 30,2009

2010Realized commodity derivative (gains) losses

$
(63,748
)
$
(23,869
)Amortization of commodity derivative premiums


16,662


16,972Unrealized commodity derivative (gains) losses for changes in fair value


56,587


(69,034
)Commodity derivative (gains) losses

$
9,501

$
(75,931
)


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

Income Tax Expense (Benefit).We incurred losses before income taxes in 2008 and 2009. These losses were a key consideration that led us
to provide a
valuation allowance against our net deferred tax assets at December 31, 2009 and September 30, 2010 since we could not conclude that it is more likely than not that the net deferred tax
assets will be fully realized. As long as we continue to conclude that we have a need for a full valuation allowance against our net deferred tax assets, we likely will not have any income tax expense
or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims, or for state income taxes. The income tax
expense we recorded for the nine months ended September 30, 2009 reflects a reduction of prior year current tax expense (a $6.6 million benefit) partially offset by federal AMT (mostly
related to the Hastings Complex sale) and state income tax expense of $2.3 million. The income tax benefit we recorded for the nine months ended September 30, 2010 primarily relates to
an increase in the estimated net operating loss carryback claims for the 2003 through 2005 tax years and a reduction in the amount owed for prior year state income taxes.

Net Income (Loss).Net income for the first nine months of 2010 was $63.1 million compared to net loss of $39.5 million for
the same
period in 2009. The change between periods is the result of the items discussed above.

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Liquidity and Capital Resources

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

Cash Flows

Nine Months Ended September 30,2009

2010(in thousands)Cash provided by operating activities

$
89,699

$
95,959Cash (used in) provided by investing activities


26,481


(59,226
)Cash (used in) provided by financing activities


(111,898
)

(37,142
)


Net
cash provided by operating activities was $96.0 million in the first nine months of 2010 compared with $89.7 million in the 2009 period. Cash flows from operating
activities in the first nine months of 2010 as compared to the 2009 period were favorably impacted by increases in commodity prices, partially offset by decreased production.

Net
cash used in investing activities was $59.2 million in the first nine months of 2010 compared with net cash provided by investing activities of $26.5 million in the
2009 period. The primary investing activities in the first nine months of 2010 were $152.4 million in capital expenditures on oil and natural gas properties related to our capital expenditure
program, partially offset by the receipt of $98.1 million in net cash proceeds from the sales of our Texas producing properties in the second quarter of 2010. The primary investing activities
in the first nine months of 2009 were the receipt of $197.7 million in cash proceeds from the sale of the Hastings Complex offset by $147.9 million in capital expenditures on oil and
natural gas properties related to our 2009 capital expenditure program and $21.3 million paid to acquire certain Sacramento Basin assets.

Net
cash used in financing activities was $37.1 million in the first nine months of 2010 compared to $111.9 million during the 2009 period. The primary financing activities
in the first nine months of 2010 were $16.9 million in net payments made on our revolving credit facility and $30.7 million of principal repayments on the second lien term loan, both of
which were primarily funded by proceeds from the sales of our producing properties in Texas. The primary financing activities in the first nine months of 2009 were $90.1 million in net payments
made on our revolving credit facility and $5.5 million of principal payments on the second lien term loan, both of which were primarily funded by proceeds from the Hastings Complex sale.
Additionally, we paid approximately $15.3 million in May 2009 to settle all financed derivative premiums.

Capital Resources and Requirements

We plan to make substantial capital expenditures in the future for the acquisition, exploration, exploitation and development of oil
and natural gas properties. We expect that our exploration, exploitation and development capital expenditures, which were $158.0 million in the first nine months of 2010, will be approximately
$220 million in 2010. Our capital budget for 2011 is $200 million. We expect to fund the remainder of our 2010 and our 2011 capital expenditure budgets primarily with cash flow from
operations, supplemented with borrowings under our revolving credit facility and proceeds from additional capital raising transactions that may include joint venture transactions related to our
Monterey shale development project, sales of non-core assets, and/or issuances of equity. If we are unable to complete any combination of the additional capital raising transactions
identified above on terms acceptable to us, we have the flexibility to reduce 2011 capital expenditures. Uncertainties relating to our capital resources and requirements in 2010 and 2011 include the
possibility that one or more of the counterparties to our hedging arrangements may fail to perform under the contracts, the

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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 December 2009, we entered into the third amended and restated credit agreement governing our
revolving credit
facility, which now has a maturity date of January 15, 2013. The agreement contains customary representations, warranties, events of default, indemnities and covenants, including covenants that
restrict our ability to incur indebtedness, require us to maintain derivative contracts covering a portion of our anticipated production and require us to maintain specified ratios of current assets
to current liabilities and debt to EBITDA. The minimum ratio of current assets to current liabilities (as those terms are defined in the agreement) is one to one; the maximum ratio of debt to EBITDA
(as defined in the agreement) is four to one. While we do not expect to be in violation of any of our debt covenants in 2010 or 2011, we believe that it will be important to monitor the debt to EBITDA
ratio requirement, especially if our EBITDA is less than we expect due to operational problems or other factors, or if our borrowing needs are greater than we expect. The agreement requires us to
reduce amounts outstanding under the facility with the proceeds of certain transactions or events, including sales of assets, in certain circumstances. The revolving credit facility is secured by a
first priority lien on substantially all of our assets.

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

The
revolving credit facility has a total capacity of $300.0 million, but is limited by a borrowing base which is currently established at $125.0 million. The borrowing
base is subject to redetermination twice each year, and may be redetermined at other times at our request or at the request of the lenders. Lending commitments under the facility have been allocated
at various percentages to a syndicate of ten banks. Certain of the institutions included in the syndicate have received support from governmental agencies in connection with events in the credit
markets. A failure of any members of the syndicate to fund under the facility, or a reduction in the borrowing base, would adversely affect our liquidity. As of October 29, 2010, we have
$20.0 million outstanding under the facility and $101.0 million in available borrowing capacity. We paid $66.9 million toward the principal balance of our revolving credit
facility during the second quarter of 2010 with the proceeds from the sales of our Texas producing properties, which we completed in the second quarter of 2010.

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

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of
principal in February 2009 after the Hastings Complex sale. The maturity date of the principal on the second lien term loan is May 8, 2014.

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

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

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

Off-Balance Sheet Arrangements

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

Risk and Insurance Program Update

Our operations are subject to all the risks normally incident to the operation and development of oil and natural gas properties and
the drilling of oil and natural gas wells, including the risk of well blowouts, oil spills and other adverse events. We could be held responsible for injuries suffered by third parties, contamination,
property damage or other losses resulting from these types of events. In addition, we have generally agreed to indemnify our drilling rig contractors against certain of these types of losses. Because
of these risks, we maintain insurance against some, but not all, of the potential risks affecting our operations and in coverage amounts and deductible levels that we believe to be economic. Our
insurance program is designed to provide us with what we believe to be an economically appropriate level of financial protection from significant unfavorable losses resulting from damages to, or the
loss of, physical assets or loss of human life or liability claims of third parties, attributed to

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certain
assets and including such occurrences as well blowouts and resulting oil spills. We regularly review our risks of loss and the cost and availability of insurance and consider the need to
revise our insurance program accordingly. Our insurance coverage includes deductibles which must be met prior to recovery. Additionally, our insurance is subject to exclusions and limitations and
there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.

In
general, our current insurance policies covering a blowout or other insurable incident resulting in damage to one of our offshore oil and gas wells provide up to $50 million of
well control, pollution cleanup and consequential damages coverage and $250 million of third party liability coverage for additional pollution cleanup and consequential damages, which also
covers personal injury and death. We expect the future availability and cost of insurance to be impacted by the recent Gulf of Mexico Deepwater Horizon incident. In particular, we expect that less
insurance coverage will be available and at a higher cost.

If
a well blowout, spill or similar event occurs that is not covered by insurance or not fully protected by insured limits, it could have a material adverse impact on our financial
condition, results of operations and cash flows. See "Risk FactorsOur business involves significant operating risks that could adversely affect our production and
could be expensive to remedy. We do not have insurance to cover all of the risks that we may face" in our Annual Report on Form 10-K for the year ended
December 31, 2009.

Remediation Plans and Procedures

As required by regulations imposed by the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, we have updated our
existing company oil-spill response plan, we continue to maintain oil spill response equipment on the platforms, including oil spill containment boom and a boat for boom deployment, and
have maintained oil-spill financial assurance in connection with our offshore operations. Our oil-spill response plan details procedures for rapid response to spill events that
may occur as a result of our operations. The plan calls for training personnel in spill response. Periodically, drills are conducted to measure and maintain the effectiveness of the plan. We review
the plan annually and update where necessary.

Also
pursuant to BOEMRE regulations, and similar regulations adopted by the California Department of Fish and Game's Office of Oil Spill Prevention and Response, we continue to be a
member of Clean Seas, LLC, or Clean Seas, a cooperative entity operated with other offshore operators to effectively respond to oil spills in the offshore region in which we operate. The
purpose of Clean Seas is to act as a resource to its member companies by providing an inventory of state-of-the-art oil spill response equipment, trained personnel,
and expertise in the planning and execution of response techniques. Clean Seas' equipment consists primarily of oil spill response vessels, including two equipped with approximately 4,500 feet of oil
spill containment boom, advanced oil recovery systems, high capacity stationary skimmers, storage tanks for recovered oil, infrared radar and advanced electronic equipment for directing and monitoring
oil spill response activities. Clean Seas also recruits and trains local fishermen to assist in oil recovery and the recovery of impacted wildlife. Clean Seas' designated area of response, which
encompasses all of our offshore operations, comprises the open oceans and coastline of the South Central Coast of California including Ventura, Santa Barbara, and San Luis Obispo Counties, and the
Santa Barbara Channel Islands.

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Item 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Derivative Transactions

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

Oil (NYMEX WTI)

Natural Gas
(NYMEX Henry Hub)Barrels/day

Weighted Avg.
Prices per Bbl

MMBtu/day

Weighted Avg.
Prices per MMBtuOctober 1 - December 31, 2010:Swaps


1,000

$
66.75





Swap arrangements(1)








11,000

$
7.00Collars(1)


5,150

$
60.00/$86.53


6,900

$
7.50/$7.00Collar arrangements(1)(2)








10,000

$
6.00/$7.00Puts


1,850

$
40.00


31,000

$
6.00January 1 - December 31, 2011:Collars(1)


5,000

$
50.00/$100.00


12,000

$
5.75/$7.12Puts(1)


2,000

$
50.00


48,000

$
6.31January 1 - December 31, 2012:Collars(1)


3,000

$
60.00/$121.10





Puts(1)








37,300

$
5.81January 1 - December 31, 2013:Collars(1)








20,000

$
5.00/$7.02


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

Floating Index

MMBtu/Day

Weighted
Avg. Basis
Differential to
NYMEX HH
(per MMBtu)Basis Swaps:October 1 - December 31, 2010

PG&E Citygate

51,618

$
0.14January 1 - December 31, 2011

PG&E Citygate

57,224

$
0.11January 1 - December 31, 2012

PG&E Citygate

47,400

$
0.28


Portfolio of Derivative Transactions

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

Oil

Type of Contract

Counterparty

Basis

Quantity
(Bbl/d)

Strike Price
($/Bbl)

TermSwap

Fortis Bank

NYMEX


1,000

$
66.75

Oct 1 - Dec 31, 10Collar

Bank of Oklahoma

NYMEX


3,500

$
60.00/$73.00

Oct 1 - Dec 31, 10Call Spread

Credit Suisse

NYMEX


3,500

$
73.00/$85.00

Oct 1 - Dec 31, 10Collar

Fortis Bank

NYMEX


1,000

$
60.00/$72.80

Oct 1 - Dec 31, 10Call Spread

Scotia Capital

NYMEX


1,000

$
72.80/$95.00

Oct 1 - Dec 31, 10Collar

Bank of Montreal

NYMEX


650

$
60.00/$81.75

Oct 1 - Dec 31, 10Put

Scotia Capital

NYMEX


1,850

$
40.00

Oct 1 - Dec 31, 10Collar

Key Bank

NYMEX


2,000

$
50.00/$141.00

Jan 1 - Dec 31, 11Call Spread

Key Bank

NYMEX


2,000

$
141.00/$100.00

Jan 1 - Dec 31, 11Collar

Credit Suisse

NYMEX


3,000

$
50.00/$140.00

Jan 1 - Dec 31, 11Call Spread

Credit Suisse

NYMEX


3,000

$
140.00/$100.00

Jan 1 - Dec 31, 11Put

Key Bank

NYMEX


2,000

$
50.00

Jan 1 - Dec 31, 11Collar

RBS

NYMEX


3,000

$
60.00/$121.10

Jan 1 - Dec 31, 12


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Table of Contents

Natural Gas

Type of Contract

Counterparty

Basis

Quantity
(MMBtu/d)

Strike Price
($/MMBtu)

TermCollar

Bank of Montreal

NYMEX


1,000

$
7.00/$9.10


Oct 1 - Dec 31, 10Call Spread

RBS

NYMEX


1,000

$
9.10/$7.00


Oct 1 - Dec 31, 10Collar

Bank of Montreal

NYMEX


900

$
7.50/$12.20


Oct 1 - Dec 31, 10Call Spread

RBS

NYMEX


900

$
12.20/$9.00


Oct 1 - Dec 31, 10Collar

Bank of Oklahoma

NYMEX


10,000

$
7.00/$10.35


Oct 1 - Dec 31, 10Call Spread

RBS

NYMEX


10,000

$
10.35/$9.00


Oct 1 - Dec 31, 10Collar

Credit Suisse

NYMEX


6,000

$
7.50/$11.95


Oct 1 - Dec 31, 10Call Spread

Credit Suisse

NYMEX


6,000

$
11.95/$9.00


Oct 1 - Dec 31, 10Call Spread

RBS

NYMEX


26,900

$
9.00/$7.00


Oct 1 - Dec 31, 10Call (sold)

RBS

NYMEX


10,000

$
9.00


Oct 1 - Dec 31, 10Put

Bank of Montreal

NYMEX


41,000

$
6.00


Oct 1 - Dec 31, 10Basis Swap

Bank of Montreal

PG&E Citygate


7,718

$
0.09


Oct 1 - Dec 31, 10Basis Swap

Bank of Oklahoma

PG&E Citygate


10,000

$
0.22


Oct 1 - Dec 31, 10Basis Swap

Credit Suisse

PG&E Citygate


7,900

$
0.05


Oct 1 - Dec 31, 10Basis Swap

Credit Suisse

PG&E Citygate


12,000

$
0.20


Oct 1 - Dec 31, 10Basis Swap

Key Bank

PG&E Citygate


14,000

$
0.10


Oct 1 - Dec 31, 10*Collar

Credit Suisse

NYMEX


12,000

$
7.50/$13.50


Jan 1 - Dec 31, 11Call (purchased)

RBS

NYMEX


12,000

$
13.50


Jan 1 - Dec 31, 11*Collar

Bank of Montreal

NYMEX


24,000

$
5.75/$7.12


Jan 1 - Dec 31, 11Call (purchased)

Bank of Montreal

NYMEX


12,000

$
7.12


Jan 1 - Dec 31, 11Put

Credit Suisse

NYMEX


10,000

$
6.00


Jan 1 - Dec 31, 11Put

Key Bank

NYMEX


14,000

$
6.00


Jan 1 - Dec 31, 11Basis Swap

Credit Suisse

PG&E Citygate


12,000

$
0.03


Jan 1 - Dec 31, 11Basis Swap

Credit Suisse

PG&E Citygate


16,000

$
0.14


Jan 1 - Dec 31, 11Basis Swap

RBS

PG&E Citygate


11,000

$
0.04


Jan 1 - Dec 31, 11Basis Swap

Scotia Capital

PG&E Citygate


6,624

$
0.03


Jan 1 - Dec 31, 11Basis Swap

Scotia Capital

PG&E Citygate


11,600

$
0.27


Jan 1 - Dec 31, 11Collar

Credit Suisse

NYMEX


15,500

$
6.00/$9.10


Jan 1 - Dec 31, 12Call (purchased)

Credit Suisse

NYMEX


15,500

$
9.10


Jan 1 - Dec 31, 12Collar

Credit Suisse

NYMEX


14,000

$
5.50/$8.00


Jan 1 - Dec 31, 12Call (purchased)

Credit Suisse

NYMEX


14,000

$
8.00


Jan 1 - Dec 31, 12Put

RBS

NYMEX


7,800

$
6.00


Jan 1 - Dec 31, 12Basis Swap

Credit Suisse

PG&E Citygate


36,000

$
0.275


Jan 1 - Dec 31, 12Basis Swap

Key Bank

PG&E Citygate


11,400

$
0.275


Jan 1 - Dec 31, 12Collar

Credit Suisse

NYMEX


20,000

$
5.00/$7.02


Jan 1 - Dec 31, 13


---

In
October 2010, we settled natural gas puts on 12,000 MMBtu per day at $7.50 per MMBtu and settled a $5.75 by $7.12 per MMBtu natural gas collar on 12,000 MMBtu per day. Both settled
contracts were effective for the period from January 1, 2011 through December 31, 2011. We received approximately $19.1 million in proceeds from the settlements. We also entered
into natural gas swaps at $4.44 per MMBtu on 24,000 MMBtu per day for the period from January 1, 2011 through December 31, 2011.

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The
following table summarizes the revisions to our portfolio of commodity derivative transactions discussed above:

Natural Gas

Type of Contract

Counterparty

Basis

Quantity
(MMBtu/d)

Strike Price
($/MMBtu)

TermSettled ContractsPut

Credit Suisse

NYMEX


12,000

$
7.50


Jan 1 - Dec 31, 11Collar

Bank of Montreal

NYMEX


12,000

$
5.75/$7.12


Jan 1 - Dec 31, 11New ContractsSwap

Scotia Capital

NYMEX


12,000

$
4.44


Jan 1 - Dec 31, 11Swap

Key Bank

NYMEX


12,000

$
4.4475


Jan 1 - Dec 31, 11


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. Most of our derivative contracts relate to changes in the market price relative to the applicable benchmark price; basis swap contracts relate to changes in the applicable differential.
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 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. Also, if 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 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

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Table of Contents

(gains)
losses on the consolidated statement of operations. As of September 30, 2010, the fair value of our commodity derivatives was a net asset of $68.5 million.

Interest Rate Derivative Transactions

We are subject to interest rate risk with respect to amounts borrowed under our credit facilities because those amounts bear interest
at variable rates. As of October 29, 2010, there was approximately $483.8 million outstanding under those facilities. We entered into interest rate swap transactions to limit our
exposure to changes in interest rates with respect to $500.0 million of variable rate borrowings through May 2014 whereby we pay a fixed interest rate of 3.840% and receive a floating interest
rate based on the one-month LIBO rate. As a result, $500 million of our variable rate debt effectively bears interest at a fixed rate of approximately 7.8% until May 2014. Accordingly, we
expect to be subject to interest rate risk until that time only with respect to variable rate borrowings in excess of $500.0 million. As of October 29, 2010, we did not have variable
rate borrowings outstanding in excess of $500 million. We expect to monitor the market for economically advantageous opportunities to reduce our interest rate swap to more closely align the
notional amount with the outstanding principal balance of our second lien term loan. As of September 30, 2010, the fair value of our interest rate derivatives was a liability of
$49.6 million.

See
notes to our condensed consolidated financial statements for a discussion of our long-term debt as of September 30, 2010.

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 September 30, 2010. Based on the evaluation, those officers believe that:



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
September 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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Table of Contents

PART IIOTHER INFORMATION

Item 1.    LEGAL PROCEEDINGS



Item 1A.    RISK FACTORS

Changes in applicable laws and regulations could increase our costs, reduce demand for our production, impede our ability to conduct operations or have other adverse effects
on our business.

Future changes in the laws and regulations to which we are subject may make it more difficult or expensive to conduct our operations
and may have other adverse effects on us. For example, the recently enacted Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Reform Act"), among other things, imposes
restrictions on the use and trading of certain derivatives, including energy derivatives. The nature and scope of those restrictions will be determined in significant part through implementing
regulations to be adopted by the SEC, the Commodities Futures Trading Commission and other regulators. We are currently assessing the likely impact of the Reform Act on our operations, and this
assessment will continue as the regulatory process contemplated by the Reform Act progresses. If, as a result of the Reform Act or its implementing regulations, capital or margin requirements or other
limitations relating to our commodity derivative activities are imposed, this could have an adverse effect on our ability to implement our hedging strategy. In particular, a requirement to post cash
collateral in connection with our derivative positions, which are currently collateralized on a non-cash basis by our oil and natural gas properties and other assets, would likely make it
impracticable to implement our current hedging strategy or to meet the hedging requirements contained in our credit facilities. In addition, requirements and limitations imposed on our derivative
counterparties could increase the costs of pursuing our hedging strategy. We are more vulnerable to the adverse consequences of changes in laws and regulations relating to derivatives than many of our
competitors because we hedge a relatively large proportion of our expected production and because our hedging strategy is integral to our overall business strategy.

In
addition, the Secretary of the U.S. Department of Interior imposed a drilling moratorium in May 2010, which delayed a planned redrill of an inactive well from Platform Gail. That
moratorium has subsequently been lifted for wells drilled from Platform Gail. However, additional moratoria, or similar rules promulgated by other governmental authorities, could have significant
impacts on our operations in the future.

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, 2009, 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



Item 3.    DEFAULTS UPON SENIOR SECURITIES



Item 4.    REMOVED AND RESERVED



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Item 5.    OTHER INFORMATION



Item 6.    EXHIBITS

Exhibit
Number

Exhibit31.1

Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31.2

Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.32

Certification of the Chief Executive Officer and the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


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SIGNATURES

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

November 1,
2010

VENOCO, INC.By:

/s/ TIMOTHY M. MARQUEZName: Timothy M. MarquezTitle:Chairman and Chief Executive OfficerBy:

/s/ TIMOTHY A. FICKERName: Timothy A. FickerTitle:Chief Financial Officer


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