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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, 2008oro

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


Commission File Number: 333-123711

Venoco, Inc.

Delaware(State or other jurisdiction of
incorporation or organization)

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

80202-1370(Zip Code)


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

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

Indicate
by check mark whether the registrant (1) has filed all reports required by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

YES
ý        NO o

Indicate by check mark whether the registrant 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, 2008, there were 51,541,102 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 in 2008, the nature, timing and
results of capital expenditure projects, amounts of future capital expenditures, our future debt levels, our receipt of approvals relating to the South Ellwood full-field development
project and our receipt of proceeds from Denbury Resources as a result of its acquisition of a portion of our producing properties in the Hastings complex, the amount of those proceeds and our use of
those proceeds. Although we believe that the expectations reflected in such forward-looking statements are reasonable, those expectations 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, 2007. 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, 2007 and such things as:



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Table of Contents

VENOCO, INC.
Form 10-Q for the Quarterly Period Ended September 30, 2008

TABLE OF CONTENTS



PART I.

FINANCIAL INFORMATIONItem 1.

Financial Statements (Unaudited)

2Condensed Consolidated Balance Sheets at December 31, 2007 and
September 30, 2008

2Condensed Consolidated Statements of Operations for the Three and Nine months
Ended September 30, 2007 and the Three and Nine months Ended September 30, 2008

3Condensed Consolidated Statements of Comprehensive Income for the Three and Nine
months Ended September 30, 2007 and the Three and Nine months Ended September 30, 2008

4Condensed Consolidated Statements of Cash Flows for the Nine months Ended
September 30, 2007 and the Nine months Ended September 30, 2008

5Notes to Condensed Consolidated Financial Statements

6Item 2.

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

30Item 3.

Quantitative and Qualitative Disclosures about Market Risk

41Item 4.

Controls and Procedures

45PART II.

OTHER INFORMATIONItem 1.

Legal Proceedings

46Item 1A.

Risk Factors

46Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

46Item 3.

Defaults upon Senior Securities

46Item 4.

Submission of Matters to a Vote of Security Holders

46Item 5.

Other Information

46Item 6.

Exhibits

46Signatures

47


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,
2007

September 30,
2008ASSETSCURRENT ASSETS:Cash and cash equivalents

$
9,735

$
4,540Accounts receivable, net of allowance for doubtful accounts of $850 at December 31, 2007 and September 30, 2008


55,597


58,101Inventories


10,377


11,191Prepaid expenses and other current assets


4,391


6,256Income tax receivable


6,725


6,325Deferred income taxes


21,967


28,906Commodity derivatives


7,780


10,805Total current assets


116,572


126,124PROPERTY, PLANT AND EQUIPMENT, AT COST:Oil and natural gas properties (full cost method, of which $12,034 and $22,822 for unproved properties were excluded from amortization at December 31,
2007 and September 30, 2008, respectively)


1,331,531


1,555,055Drilling equipment


14,460


14,460Other property and equipment


17,208


19,805Total property, plant and equipment


1,363,199


1,589,320Accumulated depletion, depreciation and amortization


(232,167
)

(325,639
)Net property, plant and equipment


1,131,032


1,263,681OTHER ASSETS:Commodity derivatives


3,768


4,619Deferred loan costs


9,699


8,010Other


4,414


2,521Total other assets


17,881


15,150TOTAL ASSETS

$
1,265,485

$
1,404,955LIABILITIES AND STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities

$
82,094

$
60,426Undistributed revenue payable


11,298


12,930Interest payable


6,839


9,209Current maturities of long-term debt


3,449


2,518Commodity and interest derivatives


68,756


89,492Total current liabilities


172,436


174,575LONG-TERM DEBT


691,896


752,765DEFERRED INCOME TAXES


16,607


37,860COMMODITY AND INTEREST DERIVATIVES


87,224


106,137ASSET RETIREMENT OBLIGATIONS


51,720


57,848Total liabilities


1,019,883


1,129,185COMMITMENTS AND CONTINGENCIESSTOCKHOLDERS' EQUITY:Common stock, $.01 par value (200,000,000 shares authorized; 50,593,403 and 51,541,102 shares issued and outstanding at December 31, 2007 and
September 30, 2008, respectively)


506


515Additional paid-in capital


309,887


316,498Retained earnings (accumulated deficit)


(62,462
)

(39,550
)Accumulated other comprehensive loss


(2,329
)

(1,693
)Total stockholders' equity


245,602


275,770TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
1,265,485

$
1,404,955


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 30,2007

2008

2007

2008REVENUES:Oil and natural gas sales

$
95,681

$
158,041

$
259,039

$
461,838Other


1,014


1,112


2,579


2,812Total revenues


96,695


159,153


261,618


464,650EXPENSES:Oil and natural gas production


28,386


42,418


79,419


107,565Transportation expense


1,141


1,655


4,425


4,334Depletion, depreciation and amortization


25,379


32,931


69,534


94,047Accretion of asset retirement obligations


895


1,044


2,512


3,065General and administrative, net of amounts capitalized


7,625


10,235


24,658


31,466Total expenses


63,426


88,283


180,548


240,477Income from operations


33,269


70,870


81,070


224,173FINANCING COSTS AND OTHER:Interest expense, net


15,493


13,305


44,595


41,063Amortization of deferred loan costs


981


735


3,211


2,623Interest rate derivative losses (gains), net


8,318


2,745


8,555


6,808Loss on extinguishment of debt








12,063


Commodity derivative losses (gains), net


9,696


(303,052
)

36,053


136,367Total financing costs and other


34,488


(286,267
)

104,477


186,861Income (loss) before income taxes


(1,219
)

357,137


(23,407
)

37,312Income tax provision (benefit)


(1,700
)

136,200


(10,400
)

14,400Net income (loss)

$
481

$
220,937

$
(13,007
)
$
22,912Earnings per common share:Basic

$
0.01

$
4.36

$
(0.29
)
$
0.45Diluted

$
0.01

$
4.23

$
(0.29
)
$
0.44Weighted average common shares outstanding:Basic


49,735


50,670


45,138


50,416Diluted


51,104


52,270


45,138


52,004


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 30,2007

2008

2007

2008Net income (loss)

$
481

$
220,937

$
(13,007
)
$
22,912OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:Hedging activities:Reclassification adjustments for settled contracts


978


259


1,462


636Changes in fair value of effective portion of outstanding hedging positions








(2,740
)

Other comprehensive income (loss)


978


259


(1,278
)

636Comprehensive income (loss)

$
1,459

$
221,196

$
(14,285
)
$
23,548


See
notes to condensed consolidated financial statements.

4

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VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In thousands)

Nine Months Ended
September 30,2007

2008CASH FLOWS FROM OPERATING ACTIVITIES:Net income (loss)

$
(13,007
)
$
22,912Adjustments to reconcile net income (loss) to net cash provided by operating activities:Depletion, depreciation and amortization


69,534


94,047Accretion of abandonment liability


2,512


3,065Deferred income taxes (benefit)


(12,411
)

14,000Share-based compensation


3,880


3,820Amortization of deferred loan costs


3,211


2,623Loss on extinguishment of debt


12,063


Unrealized interest rate swap derivative losses


8,497


(287
)Amortization of bond discounts and other non-cash interest


593


390Unrealized commodity derivative losses and amortization of premiums and other comprehensive loss


38,987


47,189Changes in operating assets and liabilities:Accounts receivable


(13,875
)

(2,504
)Inventories


112


(814
)Prepaid expenses and other current assets


739


(1,971
)Income tax receivable


170


400Other assets


(1,051
)

1,809Accounts payable and accrued liabilities


15,925


3,390Undistributed revenue payable


2,089


1,632Net premiums paid on derivative contracts


(1,907
)

(13,840
)Net cash provided by operating activities


116,061


175,861CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for oil and natural gas properties


(240,405
)

(232,709
)Acquisitions of oil and natural gas properties


(120,424
)

(10,021
)Expenditures for drilling equipment


(842
)

Expenditures for other property and equipment


(4,033
)

(3,591
)Net cash used in investing activities


(365,704
)

(246,321
)CASH FLOWS FROM FINANCING ACTIVITIES:Proceeds from long-term debt


725,421


225,000Principal payments on long-term debt


(598,516
)

(169,524
)Payments for deferred loan costs


(4,838
)

(828
)Premium to retire debt


(3,489
)

Proceeds from derivative premium financing


1,676


7,817Proceeds from exercise of stock options


3,695


2,805Excess income tax benefits from share-based compensation


2,114


Proceeds from issuance of common stock


116,595


Stock issuance costs


(561
)

(5
)Net cash provided by financing activities


242,097


65,265Net increase (decrease) in cash and cash equivalents


(7,546
)

(5,195
)Cash and cash equivalents, beginning of period


8,364


9,735Cash and cash equivalents, end of period

$
818

$
4,540Supplemental Disclosure of Cash Flow InformationCash paid for interest

$
43,174

$
38,534Cash paid for income taxes

$
1,841


Supplemental Disclosure of Non-cash ActivitiesAccrued capital expenditures at period end

$
38,730

$
19,993Increase (decrease) in accrued capital expenditures

$
785

$
(22,687
)


See notes to condensed consolidated financial statements.

5

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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 California and the Gulf Coast of Texas.

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. Venoco's Annual Report on Form 10-K for the year ended December 31, 2007 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 impairment tests of long-lived assets;
(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 derivative instruments; (8) accrued liabilities; (9) valuation of share-based payments
and (10) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Income TaxesThe Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated
annual effective rate to its year-to-date income or loss, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific
transaction occurs. For the nine months ended September 30, 2008, the Company's overall effective tax rate for continuing operations was different than the statutory rate of 35% primarily due
to state income taxes. The Company expects its effective tax rate to be approximately 38% for the remainder of 2008.

Earnings Per ShareStatement of Financial Accounting Standards No. 128,Earnings Per
Share, requires presentation of "basic" and "diluted" earnings per share. Basic earnings per common share of stock is calculated by dividing net income (loss) by the weighted
average number of common shares outstanding during each period. The weighted average number of common shares outstanding used to calculate basic net income (loss) per share excludes the effect of
non-vested restricted shares subject to future vesting. As those restricted shares vest, they will be included in the shares outstanding used to calculate basic earnings per common share
(although all restricted shares are issued and outstanding upon grant). Diluted earnings per common share of stock is calculated by dividing net income by the weighted average number of common shares
outstanding and other dilutive securities. The Company's dilutive securities include non-qualified stock option awards and non-vested restricted shares with

6

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

service
conditions. Non-vested restricted shares with service and market conditions are excluded from basic earnings per common share calculations until they vest.

The
treasury stock method is used to measure the dilutive impact of stock options. The following table details the weighted average dilutive and anti-dilutive securities
related to stock options for the periods presented:

Three Months Ended September 30,

Nine Months Ended September 30,2007

2008

2007

2008Dilutive


4,106,582


3,136,245





3,342,637Anti-dilutive


211,875


547,803


4,603,349


607,782


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 30,2007

2008

2007

2008Net income (loss)

$
481

$
220,937

$
(13,007
)
$
22,912Adjustments to net income for dilution











Net income (loss) adjusted for the effect of dilution

$
481

$
220,937

$
(13,007
)
$
22,912Basic weighted average common shares outstanding


49,735


50,670


45,138


50,416Add: dilutive effect of stock options


1,339


1,230





1,297Add: dilutive effect of non-vested restricted stock


30


370





291Diluted weighted average common shares outstanding


51,104


52,270


45,138


52,004Basic earnings per common share

$
0.01

$
4.36

$
(0.29
)
$
0.45Diluted earnings per common share

$
0.01

$
4.23

$
(0.29
)
$
0.44


ReclassificationsThe Company made certain reclassifications to prior period condensed consolidated statements of operations
to be consistent with the current presentation. The condensed consolidated statements of operations were modified to separately disclose interest rate derivative losses. In addition, commodity
derivative (gains) losses were reclassified from revenues to financing costs and other in the condensed consolidated statements of operations so as not to distort revenue trends with significant
non-designated future economic hedging. These reclassifications had no impact on the Company's financial position, income (loss) before taxes or cash flows from operating, investing or
financing activities.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)



In April 2007, the FASB issued FSP No. FIN 39-1,Amendment of FASB Interpretation
No. 39, ("FIN 39-1") to amend FIN 39,Offsetting of Amounts Related to Certain Contracts("FIN 39"). The terms "conditional contracts" and "exchange contracts" used in FIN 39 have been replaced with the more general term "derivative contracts." In addition,
FIN 39-1 permits the offsetting of recognized fair values for the right to reclaim cash collateral or the obligation to return cash collateral against fair values of
derivatives under certain circumstances, such as under master netting arrangements. Additional disclosure is also required regarding a company's accounting policy with respect to offsetting fair value
amounts. The guidance in FIN 39-1 is effective for fiscal years beginning after November 15, 2007, with early application allowed. The effects of initial adoption
should be recognized as a change in accounting principle through retrospective application for all periods presented. The Company adopted FIN 39-1 and no change in accounting
principle was necessary. There was no impact on the Company's operating results, financial position or cash flows.

In
February 2007, the FASB issued Statement No. 159,The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of
FASB Statement No. 115("SFAS 159"), which permits entities to choose to measure many financial instruments and certain other items at fair value (the Fair
Value Option). Election of the Fair Value Option is made on an
instrument-by-instrument basis and is irrevocable. At the adoption date, unrealized gains and losses on financial assets and liabilities for which the Fair Value Option has
been elected would be reported as a cumulative adjustment to beginning retained earnings. If the Company elects the Fair Value Option for certain financial assets and liabilities, the Company will
report unrealized gains and losses due to changes in fair value in earnings at each subsequent reporting date. The provisions of SFAS 159 are effective January 1, 2008. The Company
adopted SFAS 159 as of January 1, 2008, and the adoption did not have a material impact on the Company's operating results, financial position or cash flows as the Company did not elect
the Fair Value Option for any of its financial assets or liabilities, except for derivatives that are already at fair value.

In
March 2008, the FASB issued Statement No. 161,Disclosure about Derivative Instruments and Hedging Activitiesan amendment to FASB
Statement No. 133("SFAS 161"). SFAS 161 expands interim and annual disclosures about derivative and hedging activities that are intended to better convey
the purpose of derivative use and the risks managed. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008. The adoption of SFAS 161 is not
expected to have an impact on the Company's consolidated financial statements, other than additional disclosures.

In
September 2008, the FASB issued FSP No. FAS 133-1 and FIN 45-4,Disclosures about Credit Derivatives and Certain
Guarantees: An Amendment of FASB Statement No. 133("SFAS 133")and FASB Interpretation No. 45("FIN 45"); and Clarification of the Effective Date of FASB Statement No. 161("SFAS 161"). The FSP amends SFAS 133 to
require disclosures by sellers of credit derivatives, including credit derivatives embedded in hybrid instruments. The FSP also amends FIN 45 to require additional disclosure about the current
status of the payment/performance risk of a guarantee. The provisions that amend SFAS 133 and FIN 45 are effective for periods ending after November 15, 2008. Additionally, the
FSP clarifies the effective date of SFAS 161 by stating that the disclosures required by SFAS 161 should be provided for any reporting period (annual or quarterly interim) beginning
after

8

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

November 15,
2008. The adoption by the Company is not expected to have a material effect on the Company's consolidated financial statements, other than additional disclosures.

In
June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1,Determining Whether Instruments Granted in Share-Based
Payment Transactions Are Participating Securities("FSP 03-6-1"). FSP 03-6-1 addresses whether instruments
granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (EPS) under the
two-class method described in FASB Statement No. 128,Earnings per Share. The FSP concludes that unvested share-based payment awards
that contain nonforfeitable rights to dividends or dividend equivalents are participating securities and shall be included in the computation of EPS pursuant to the two-class method. The
statement is effective for fiscal years beginning after December 15, 2008, and interim periods within those years. All prior-period EPS data presented is to be adjusted retrospectively to
conform to the provisions of this FSP. The Company's restricted stock awards contain dividend rights. The Company does not expect material changes to the
Company's consolidated financial statements as a result of the adoption of this FSP, since the Company is precluded from issuing dividends under terms of its debt agreements.

In
December 2007, the FASB issued Statement No. 141R,Business Combinations("SFAS 141R"). SFAS 141R
establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any
noncontrolling interest in the acquiree. The statement also provides guidance for recognizing and measuring the goodwill acquired in business combinations and determines what information to disclose
to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The statement applies prospectively to business combinations for which the
acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. SFAS 141R may have an impact on the Company's consolidated
financial statements when effective, but the nature and magnitude of the specific effects will depend upon the nature, terms and size of the acquisitions the Company consummates after the
effective date.

In
September 2006, the FASB issued SFAS No. 157,Fair Value Measurements("SFAS 157"), which defines fair
value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This pronouncement applies to other standards that require or permit fair value
measurements. Accordingly, this statement does not require any new fair value measurements. The Company adopted the provisions of SFAS 157 on January 1, 2008. See "Fair Value
Measurements" below for more details.

Fair Value MeasurementsIn September 2006, the FASB issued SFAS 157, which defines fair value, establishes a
framework for measuring fair value, and expands disclosures about fair value measurements. The provisions of SFAS 157 are effective January 1, 2008. The FASB has also issued Staff
Position FAS 157-2 (FSP No. 157-2), which delays the effective date of SFAS 157 for nonfinancial assets and liabilities, except for items that are
recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. The Company adopted
SFAS 157 as of January 1, 2008 for all financial and nonfinancial assets and liabilities recognized or disclosed at fair value on a recurring basis. The Company elected to defer the
application thereof to nonfinancial assets and liabilities in accordance with FSP No. 157-2. Non-recurring nonfinancial assets and nonfinancial liabilities for which the
Company has not applied

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

the
provisions of SFAS 157 include those measured at fair value in impairment testing for unproved properties, asset retirement obligations initially measured at fair value, and those initially
measured at fair value in a business combination.

As
defined in SFAS 157, fair value is 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.
SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for
identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).

The
three levels of the fair value hierarchy defined by SFAS 157 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 1 primarily consists of financial instruments such as exchange-traded
derivatives and listed equities.

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. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various
assumptions, including quoted forward prices for interest rates and commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as
other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are
supported by observable levels at which transactions are executed in the marketplace. Instruments in this category generally include non-exchange-traded derivatives such as commodity
swaps, interest rate swaps, options and collars.

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. Instruments in this category generally include non-exchange-traded derivatives such as commodity swaps, options and
collars that are valued similar to the industry-standard models described above, however, these derivatives are classified in Level 3 because of inputs that may not be observable.

As
required by SFAS 157, 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.

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

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, 2008
(in thousands).

Level 1

Level 2

Level 3

Fair Value
as of
September 30,
2008Assets (Liabilities):Commodity derivatives

$


$
15,424

$


$
15,424Commodity derivatives





(178,109
)




(178,109
)Interest rate swaps





(17,520
)




(17,520
)


The
fair value of the interest rate swaps are valued using Level 2 fair value methodologies. The Company is able to value the assets and liabilities based on observable market
data for similar instruments. This observable data includes the forward curve for interest rates based on quoted market prices.

In
the first quarter of 2008, commodity derivative instruments were classified as a Level 3 measurement because the Company was unable to document certain observable factors. In
the second quarter of 2008, the commodity derivatives previously classified as a Level 3 measurement were transferred to a Level 2 measurement classification due to additional
documentation obtained by the Company to support such a classification. The table below presents a reconciliation for the liabilities measured at fair value on a recurring basis using significant
unobservable inputs (Level 3) during the nine month period ended September 30, 2008 (in thousands).

Nine Months
Ended
September 30,
2008Beginning Balance

$
(126,625
)Realized and Unrealized Losses(1)


(56,373
)Purchases, issuances and settlements


8,510Transfers in and out of Level 3


174,488Balance as of September 30, 2008

$
Change in unrealized gains (losses) included in earnings relating to Level 3 derivatives still held as of September 30, 2008

$



---

2. ACQUISITIONS AND SALES OF PROPERTIES

West Montalvo and Manvel acquisitions.The Company acquired the West Montalvo field in Ventura County, California in May 2007 for approximately
$61.3 million. The Company acquired the Manvel field in Brazoria County, Texas, and certain other fields in Texas, in April 2007 for $44.5 million.

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

2. ACQUISITIONS AND SALES OF PROPERTIES (Continued)

The
following unaudited pro forma condensed consolidated operating results for the nine months ended September 30, 2007 gives effect to the West Montalvo and Manvel
acquisitions as if they had been completed as of January 1, 2007. The pro forma amounts shown below are not necessarily indicative of the operating results that would have occurred if
the transaction had occurred on such date. The pro forma adjustments made are based on certain assumptions that the Company believes are reasonable based on information available at the time
they were prepared (in thousands, except per share amounts) (unaudited).

Nine Months
Ended
September 30,
2007Pro FormaTotal revenues

$
270,963Net income (loss)

$
(10,950
)Basic earnings per common share

$
(0.24
)Diluted earnings per common share

$
(0.24
)


Willows-Beehive.The Company acquired additional working interests in the Arbuckle, Beehive Bend, and Bounde Creek fields in March 2008 for approximately
$4.5 million. All fields are located in the Sacramento Basin in California.

Grayson County.In September 2008, the Company acquired working interests in approximately 11,000 undeveloped acres located in Grayson County, Texas for
approximately $5.0 million, subject to normal closing adjustments, from an entity (the "Seller") affiliated with a former member of the Company's board of directors. Under terms of the purchase
and sale agreement, the Company agreed to drill two horizontal test wells on the acreage by March 2010. The Seller has the option to participate on a 12.5% working interest basis in any wells
the Company drills beyond the two test wells. The Company is required to carry the Seller's costs on wells drilled subsequent to the test wells until the Company has incurred costs of approximately
$5.7 million, net to the Seller's 12.5% working interest. If the Company has not incurred such costs by September 2011, it will be required to pay Seller the difference between
$5.7 million and amounts actually incurred, or reassign its interest in the then undeveloped acreage to Seller.

The
board member resigned from the Company's board of directors on August 29, 2008, prior to the execution of a definitive agreement relating to the acquisition.

Hastings Complex Sale.In November 2006, the Company entered into an agreement with a subsidiary of Denbury Resources Inc. pursuant to which Denbury
acquired an option to acquire the majority of the Company's properties in the Hastings complex for use in a proposed CO2 enhanced recovery project in which the Company will have a
continuing interest. On August 29, 2008, the Company entered into an amendment to the agreement pursuant to which Denbury exercised its option to acquire the properties effective
January 1, 2009. Denbury will either purchase the properties or, at the Company's option, enter into a volumetric production payment or similar arrangement with the Company with respect to the
properties. Unless the Company and Denbury agree otherwise, the purchase price or volumetric production payment will be based on the value of the properties as of

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

2. ACQUISITIONS AND SALES OF PROPERTIES (Continued)

December 31,
2008 determined with reference to the net proved reserves associated with the properties based on then-existing operations and NYMEX forward strip pricing, subject to certain
adjustments.

3. LONG-TERM DEBT

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

December 31,
2007

September 30,
2008Revolving credit agreement due March 2011

$
42,000

$
100,000Second lien term loan due September 2011


500,000


500,0008.75% senior notes due December 2011


149,453


149,556Financed derivative premiums due through 2011


3,892


5,727Total long-term debt


695,345


755,283Less: current portion of long-term debt


3,449


2,518Long-term debt, net of current portion

$
691,896

$
752,765


Revolving credit facility.The Company has a $300.0 million revolving credit facility with a syndicate of banks ("revolving credit facility"). In
May 2008, the revolving credit facility was amended to, among other things, extend the maturity date to March 30, 2011 and increase the borrowing base from $140.0 million to
$200.0 million. The revolving credit 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 was 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 revolving credit agreement. Loans designated as Base Rate Loans under the revolving
credit facility bear interest at a floating rate equal to (i) the greater of a market base rate and the overnight federal funds rate plus 0.50% plus (ii) an applicable margin ranging
from zero to 0.75%, based upon utilization. Loans designated as LIBO Rate Loans under the revolving credit facility bear interest at (i) LIBOR plus (ii) an applicable margin ranging from
1.50% to 2.25%, based upon utilization. A commitment fee ranging from 0.375% to 0.5% 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 is subject to redetermination in April and
November of each year. As of November 5, 2008, the Company had effective available borrowing capacity of $79.8 million (net of $1.2 million in outstanding letters of credit
and $4.75 million attributable to Lehman Commercial Papersee below) under the revolving credit facility.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

3. LONG-TERM DEBT (Continued)

The borrowing base under the Company's revolving credit facility is currently $200.0 million and has
been allocated at various percentages to a syndicate of 12 banks. Certain of the institutions included in the syndicate have received support from governmental agencies in connection with
recent events in the credit markets. In addition, 4.75% of the $200.0 million borrowing base has been allocated to Lehman Commercial Paper ("LCP"), a wholly-owned subsidiary of Lehman Brothers
Holding, Inc., which filed for bankruptcy protection on September 15, 2008. LCP is no longer funding its portion of the Company's borrowing requests made under the facility. As of
November 5, 2008, the Company owed LCP $4.75 million. The Company's effective borrowing base is $195.25 million, excluding $4.75 million related to LCP.

Second lien term loan facility.The Company entered into its $500.0 million senior secured second lien term loan facility in May 2007. Loans made
under the 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
term loan agreement 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. Principal on the facility is payable on
May 8, 2014. However, if the senior notes (see below) are not refinanced in full prior to September 20, 2011, principal on the new facility will be payable on that date.

The
Company may from time to time make optional prepayments of amounts borrowed under the facility if no amounts are outstanding under the revolving credit facility. Optional prepayments
made prior to May 7, 2009 are subject to a prepayment premium of 1%. After that date, no premium will be payable with respect to any optional prepayment. Amounts prepaid under the facility may
not be reborrowed.

Senior notes.In December 2004, the Company issued $150.0 million in 8.75% senior notes (the "senior notes") due December 2011.
Interest on the senior notes is due each June 15 and December 15. The senior notes are senior 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 were issued as unsecured obligations, but are
currently secured equally and ratably with the Company's second lien term loan facility.

The
Company was in compliance with all debt covenants at September 30, 2008.

Financed Derivative Premiums.The Company has entered into derivative contracts that contain provisions for the deferral of the payment or receipt of premiums
until the period of production for which the derivative contract relates. Both the derivative and the net liability for the payment of premiums were recorded at their fair values at the inception of
the derivative contracts.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS

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 limit future revenues from favorable price movements. The use of derivatives also involves the risk that the counterparties to such instruments will be unable to
meet the financial terms of such contracts.

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 30,2007

2008

2007

2008Realized commodity derivative (gains) losses

$
(530
)
$
34,095

$
(554
)
$
90,214Amortization of commodity derivative premiums


1,650


1,626


5,179


5,155Unrealized commodity derivative (gains) losses:Change in fair value of derivatives that do not qualify for hedge accounting


8,576


(338,773
)

31,541


40,998Ineffective portion of derivatives qualifying for hedge accounting








(113
)

Total unrealized commodity derivative (gains) losses


8,576


(338,773
)

31,428


40,998Commodity derivative (gains) losses

$
9,696

$
(303,052
)
$
36,053

$
136,367


Because
a large portion of the Company's commodity derivatives do not qualify for hedge accounting and to increase clarity in its financial statements, the Company elected to discontinue
hedge accounting prospectively for its commodity derivatives beginning April 1, 2007. Consequently, from that date forward, the Company has recognized mark-to-market
gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (loss) for those commodity derivatives that qualify as cash flow hedges. The net
mark-to-market loss on outstanding derivatives on the date the Company discontinued hedge accounting included in accumulated other comprehensive loss of $8.3 million
($5.1 million after tax) is being amortized into future earnings as the original hedged transactions affect earnings. This change in reporting has no impact on the Company's reported cash
flows, although future results of operations are affected by mark-to-market gains and
losses which fluctuate with volatile oil and gas prices. The Company amortized accumulated other comprehensive loss into oil and natural gas sales of $1.6 million and $0.4 million during
the quarters ended September 30, 2007 and 2008, respectively, and $2.4 million and $1.0 million for the nine month periods ended September 30, 2007 and 2008, respectively.

As
of September 30, 2008, the remaining unrealized derivative fair value loss of $2.7 million ($1.7 million after tax) for derivative contracts previously designated
as cash flow hedges is recorded in accumulated other comprehensive loss. The Company will amortize net unrealized derivative losses of $2.2 million ($1.4 million after tax) out of
accumulated other comprehensive loss into earnings during the next twelve months.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

Crude Oil Agreements.As of September 30, 2008, the Company had entered into option, swap and collar agreements to receive average minimum and maximum
New York Mercantile Exchange (NYMEX) West Texas Intermediate (WTI) prices as summarized below. Location and quality differentials attributable to the Company's properties are not included in
the following prices. The agreements provide for monthly settlement based on the differential between the agreement price and the actual NYMEX crude oil price.

MinimumMaximumAvg. PricesBarrels/day

Barrels/day

Avg. PricesCrude oil derivatives at September 30, 2008 for production:October 1December 31, 2008


8,100

$
59.20


8,100

$
73.65January 1December 31, 2009


6,983

$
58.09


6,983

$
74.38January 1December 31, 2010


6,150

$
61.10


6,150

$
72.88January 1December 31, 2011


7,000

$
70.00


7,000

$
141.64


Natural Gas Agreements.As of September 30, 2008, the Company had entered into option, swap and collar agreements to receive average minimum and maximum
PG&E Citygate prices as follows:

Minimum

MaximumMMBtu/Day

Avg. Prices

MMBtu/Day

Avg. PricesNatural gas derivatives at September 30, 2008 for production:October 1December 31, 2008


32,650

$
7.67


31,032

$
11.47January 1December 31, 2009


33,125

$
7.87


23,125

$
11.42January 1December 31, 2010


17,900

$
7.32


17,900

$
11.03January 1December 31, 2011


12,000

$
7.50


12,000

$
13.50


Interest Rate Swap.The Company entered into an interest rate swap transaction during 2006 to lock in its interest cost on $200.0 million of borrowings
under its second lien term loan facility through May 2008. The Company pays a fixed interest rate of 5.4225% and receives a floating interest rate based on the three-month LIBO rate.
Settlements are made quarterly. In June 2007, the Company entered into an additional interest rate swap relating to borrowings under the second lien term loan. The swap fixes the interest rate
on $300.0 million of borrowings through May 2008 and on $500.0 million of borrowings from May 2008 through June 2010. The Company pays a fixed interest rate of 5.32%
and receives a floating interest rate based on the three-month LIBO rate, with settlements made quarterly. As a result of these transactions, amounts borrowed under the second lien term loan facility
will effectively bear interest at a fixed rate of approximately 9.3% until June 2010 (including the 4.0% margin payable on borrowed amounts). The Company has not designated either interest rate
swap as a hedge.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

The
components of 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 30,2007

2008

2007

2008Realized interest rate derivative (gains) losses

$
3

$
3,371

$
58

$
7,095Unrealized interest rate derivative (gains) losses


8,315


(626
)

8,497


(287
)Interest rate derivative (gains) losses, net

$
8,318

$
2,745

$
8,555

$
6,808


The
estimated fair values of derivatives included in the consolidated balance sheets at December 31, 2007 and September 30, 2008 are summarized below. The net fair value of
the Company's derivatives increased by $35.8 million from a net liability of $144.4 million at December 31, 2007 to a net liability of $180.2 million at
September 30, 2008 due to higher futures prices for crude oil and natural gas, which are used in the calculation of the fair value of commodity derivatives, and lower estimated futures interest
rates, which are used in the calculation of the fair value of interest derivatives. As of the dates indicated, the Company's derivative assets and liabilities consisted of the following
(in thousands):

December 31,
2007

September 30,
2008Derivative assets:Oil derivative contracts

$
3,341

$
2,889Gas derivative contracts


8,207


12,535Derivative liabilities:Oil derivative contracts


(134,505
)

(176,970
)Gas derivative contracts


(3,668
)

(1,139
)Interest rate derivative contracts


(17,807
)

(17,520
)Net derivative liability

$
(144,432
)
$
(180,205
)


5. 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 asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The asset retirement liability is accreted to its
present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

5. ASSET RETIREMENT OBLIGATIONS (Continued)

The
following table summarizes the activities for the Company's asset retirement obligations for the nine months ended September 30, 2007 and 2008 (in thousands):

Nine Months Ended
September 30,
2007

Nine Months Ended
September 30,
2008Asset retirement obligations at beginning of period

$
42,049

$
52,220Revisions of estimated liabilities


2,596


582Liabilities incurred


4,675


2,767Liabilities settled


(110
)

(286
)Accretion expense


2,512


3,065Asset retirement obligations at end of period


51,722


58,348Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)


(7,244
)

(500
)Long-term asset retirement obligations

$
44,478

$
57,848


6. CAPITAL STOCK

The Company has 57.3 million shares of common stock issued or reserved for issuance at September 30, 2008, including 5.5 million shares reserved for issuance under
the Company's stock incentive plans. At September 30, 2008, the Company has 51.5 million common shares issued and outstanding, of which 845,056 shares are restricted stock granted
under the Company's 2005 stock incentive plan. At September 30, 2008, the Company had approximately 3.7 million options outstanding and 1.8 million shares available to be issued
pursuant to awards under its stock incentive plans.

7. SHARE-BASED PAYMENTS

The Company has granted options to directors, certain employees and officers of the Company other than its CEO. As of September 30, 2008, there are a total of
3,672,203 options outstanding with a weighted average exercise price of $9.45 ($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 will generally vest upon a change in control of the Company. The agreements with employee option holders generally provide that all of the
holder's options will vest if the Company terminates the holder's employment, unless the termination is for specified types of misconduct. The agreements with director option holders provide that any
unvested options will terminate when the director's service to the Company ceases.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

7. SHARE-BASED PAYMENTS (Continued)

The
following summarizes the Company's stock option activity for the nine months ended September 30, 2008:

Shares

Weighted
Average
Exercise
PriceOutstanding, beginning of period


4,159,463

$
9.19Granted





Exercised


(450,460
)

6.59Cancelled


(36,800
)

15.28Outstanding, end of period


3,672,203

$
9.45Exercisable, end of period


2,632,330

$
8.75


As
of September 30, 2008, there are a total of 845,056 shares of restricted stock outstanding under the Company's 2005 stock incentive plan, including
365,773 granted to its CEO. The restricted shares generally vest over a four year service period. The vesting of 482,851 of the 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 estimated grant date fair values of restricted share awards are recognized as expense over the
requisite service periods. As of September 30, 2008, none of the shares subject to market conditions have vested. Holders of restricted shares forfeited 11,023 shares in connection with
tax withholding on their vested restricted shares. All forfeited restricted share awards are cancelled.

The
following summarizes the Company's unvested restricted stock award activity for the nine months ended September 30, 2008:

Shares

Weighted Average
Grant Date
Fair ValueNon-vested at beginning of period


376,635

$
14.32Granted


515,693


11.96Vested


(33,991
)

15.34Forfeited


(13,281
)

13.12Non-vested at September 30, 2008


845,056

$
12.84


The
Company recognized total share-based compensation expense of $1.3 million during each of the quarters ended September 30, 2007 and 2008, and $3.9 million and
$3.8 million for the nine month periods ended September 30, 2007 and 2008, respectively. As of September 30, 2008, there was $2.8 million of total unrecognized compensation
cost related to stock options which is expected to be amortized over a weighted-average period of 1.9 years and $7.8 million of total unrecognized compensation cost related to restricted
stock which is expected to be amortized over a weighted-average period of 3.1 years.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

8. LITIGATION



Between June 2003 and April 2005, six lawsuits were filed against the Company and certain other energy companies in Los
Angeles County Superior Court by persons who attended Beverly Hills High School or who were or are citizens of Beverly Hills/Century City or visitors to that area during the time period running from
the 1930s to date. There are approximately 1,000 plaintiffs (including plaintiffs in two related lawsuits in which the Company has not been named) who claimed to be suffering from various forms
of cancer or other illnesses, fear they may suffer from such maladies in the future, or are related to persons who have suffered from cancer or other illnesses. Plaintiffs alleged that exposure to
substances in the air, soil and water that originated from either oil-field or other operations in the area were the cause of the cancers and other maladies. The Company has owned an oil
and natural gas facility adjacent to the school since 1995. For the majority of the plaintiffs, their alleged exposures occurred before the Company acquired the facility. All cases were consolidated
before one judge. Twelve "representative" plaintiffs were selected to have their cases tried first, while all of the other plaintiffs' cases were stayed. In November 2006, the judge entered
summary judgment in favor of all defendants in the test cases, including the Company. The judge dismissed all claims by the test case plaintiffs on the ground 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 2009. 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. The Company has appealed the Santa Barbara Court's ruling. 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, it will not
have the protection of those policies with respect to any damages or settlement costs ultimately incurred in the lawsuits.

In
accordance with SFAS No. 5,Accounting for Contingencies, 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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

8. LITIGATION (Continued)

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.



The Company pays royalties to the state of California pursuant to certain oil and natural gas leases relating to the South Ellwood
field. The Company has been informed by the California State Lands Commission (the "SLC") that the SLC is in the process of auditing the Company's royalty payment calculations on those leases.
The SLC has not completed its audit, nor has it presented the Company with any audit conclusions. The Company does not currently expect that the audit adjustments, if any, will be material.



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

9. GUARANTOR FINANCIAL INFORMATION

Company subsidiaries TexCal Energy (LP) LLC and its two subsidiaries, Catco Energy LLC and Whittier Pipeline Corp. (the "Guarantor Subsidiaries") have fully and
unconditionally guaranteed, on a joint and several basis, the Company's obligations under the senior notes. The Company has one subsidiary, Ellwood Pipeline, Inc., that 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, 2008. 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.

21

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Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS        THREE MONTHS ENDED SEPTEMBER 30, 2007 (Unaudited)        (in thousands)

Venoco, Inc.

Guarantor Subsidiaries

Non-Guarantor Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
62,867

$
32,814

$


$


$
95,681Other


872


12


1,425


(1,295
)

1,014Total revenues


63,739


32,826


1,425


(1,295
)

96,695EXPENSES:Oil and natural gas production


18,242


9,844


300





28,386Transportation expense


2,362


4





(1,225
)

1,141Depletion, depreciation and amortization


18,881


6,476


22





25,379Accretion of abandonment liability


740


145


10





895General and administrative, net of amounts capitalized


7,512


113


70


(70
)

7,625Total Expenses


47,737


16,582


402


(1,295
)

63,426Income from operations


16,002


16,244


1,023





33,269FINANCING COSTS AND OTHER:Interest expense, net


16,153


29


(689
)




15,493Amortization of deferred loan costs


981











981Interest rate derivative losses, net


8,318











8,318Loss on extinguishment of debt














Commodity derivative losses (gains), net


9,696











9,696Total financing costs and other


35,148


29


(689
)




34,488Equity in subsidiary income


9,358








(9,358
)

Income (loss) before income taxes


(9,788
)

16,215


1,712


(9,358
)

(1,219
)Income tax provision (benefit)


(10,269
)

7,670


899





(1,700
)Net income (loss)

$
481

$
8,545

$
813

$
(9,358
)
$
481


22

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Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS        THREE MONTHS ENDED SEPTEMBER 30, 2008 (Unaudited)        (in thousands)

Venoco, Inc.

Guarantor Subsidiaries

Non-Guarantor Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
116,852

$
41,189

$


$


$
158,041Other


1,037


(14
)

1,548


(1,459
)

1,112Total revenues


117,889


41,175


1,548


(1,459
)

159,153EXPENSES:Oil and natural gas production


28,086


13,704


628





42,418Transportation expense


3,036


3





(1,384
)

1,655Depletion, depreciation and amortization


27,283


5,625


23





32,931Accretion of asset retirement obligations


827


202


15





1,044General and administrative, net of amounts capitalized


9,165


1,070


75


(75
)

10,235Total expenses


68,397


20,604


741


(1,459
)

88,283Income from operations


49,492


20,571


807





70,870FINANCING COSTS AND OTHER:Interest expense, net


14,124


(2
)

(817
)




13,305Amortization of deferred loan costs


735











735Interest rate derivative losses, net


2,745











2,745Loss on extinguishment of debt














Commodity derivative losses (gains), net


(303,052
)










(303,052
)Total financing costs and other


(285,448
)

(2
)

(817
)




(286,267
)Equity in subsidiary income


13,395








(13,395
)

Income (loss) before income taxes


348,335


20,573


1,624


(13,395
)

357,137Income tax provision (benefit)


127,398


8,161


641





136,200Net income (loss)

$
220,937

$
12,412

$
983

$
(13,395
)
$
220,937


23

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Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS        NINE MONTHS ENDED SEPTEMBER 30, 2007 (Unaudited)        (in thousands)

Venoco, Inc.

Guarantor Subsidiaries

Non-Guarantor Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
191,544

$
67,495

$


$


$
259,039Other


2,171


49


3,840


(3,481
)

2,579Total revenues


193,715


67,544


3,840


(3,481
)

261,618EXPENSES:Oil and natural gas production


51,783


26,400


1,236





79,419Transportation expense


7,692


4





(3,271
)

4,425Depletion, depreciation and amortization


54,822


14,655


57





69,534Accretion of abandonment liability


2,097


398


17





2,512General and administrative, net of amounts capitalized


22,974


1,683


211


(210
)

24,658Total Expenses


139,368


43,140


1,521


(3,481
)

180,548Income from operations


54,347


24,404


2,319





81,070FINANCING COSTS AND OTHER:Interest, net


46,590


(16
)

(1,979
)




44,595Amortization of deferred loan costs


3,211











3,211Interest rate derivative losses, net


8,555











8,555Loss on extinguishment of debt


12,063











12,063Commodity derivative losses (gains), net


36,053











36,053Total financing costs and other


106,472


(16
)

(1,979
)




104,477Equity in subsidiary income


15,972








(15,972
)

Income (loss) before income taxes


(36,153
)

24,420


4,298


(15,972
)

(23,407
)Income tax provision (benefit)


(23,146
)

10,838


1,908





(10,400
)Net income (loss)

$
(13,007
)
$
13,582

$
2,390

$
(15,972
)
$
(13,007
)


24

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Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS        NINE MONTHS ENDED SEPTEMBER 30, 2008 (Unaudited)        (in thousands)

Venoco, Inc.

Guarantor Subsidiaries

Non-Guarantor Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
339,307

$
122,531

$


$


$
461,838Other


2,419


11


3,951


(3,569
)

2,812Total revenues


341,726


122,542


3,951


(3,569
)

464,650EXPENSES:Oil and natural gas production


68,465


37,523


1,577





107,565Transportation expense


7,674


7





(3,347
)

4,334Depletion, depreciation and amortization


76,247


17,731


69





94,047Accretion of asset retirement obligations


2,426


592


47





3,065General and administrative, net of amounts capitalized


28,872


2,594


222


(222
)

31,466Total expenses


183,684


58,447


1,915


(3,569
)

240,477Income from operations


158,042


64,095


2,036





224,173FINANCING COSTS AND OTHER:Interest expense, net


43,428


(16
)

(2,349
)




41,063Amortization of deferred loan costs


2,623











2,623Interest rate derivative losses, net


6,808











6,808Loss on extinguishment of debt














Commodity derivative losses (gains), net


136,367











136,367Total financing costs and other


189,226


(16
)

(2,349
)




186,861Equity in subsidiary income


42,063








(42,063
)

Income (loss) before income taxes


10,879


64,111


4,385


(42,063
)

37,312Income tax provision (benefit)


(12,033
)

24,741


1,692





14,400Net income (loss)

$
22,912

$
39,370

$
2,693

$
(42,063
)
$
22,912


25

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Table of Contents

CONDENSED CONSOLIDATING BALANCE SHEETS        AT DECEMBER 31, 2007        (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-
Guarantor
Subsidiary

Eliminations

ConsolidatedASSETSCURRENT ASSETS:Cash and cash equivalents

$
8,762

$
973

$


$


$
9,735Accounts receivable


38,020


17,512


65





55,597Inventories


5,217


5,160








10,377Prepaid expenses and other current assets


4,391











4,391Income taxes receivable


6,725











6,725Deferred income taxes


21,967











21,967Commodity derivatives


7,780











7,780TOTAL CURRENT ASSETS


92,862


23,645


65





116,572PROPERTY, PLANT & EQUIPMENT, NET


755,487


374,246


1,299





1,131,032COMMODITY DERIVATIVES


3,768











3,768INVESTMENTS IN AFFILIATES


431,083








(431,083
)

OTHER


13,296


817








14,113TOTAL ASSETS

$
1,296,496

$
398,708

$
1,364

$
(431,083
)
$
1,265,485LIABILITIES AND
STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities

$
75,524

$
6,570

$


$


$
82,094Undistributed revenue payable


11,298











11,298Interest payable


6,839











6,839Current maturities of long-term debt


3,449











3,449Commodity and interest derivatives


68,756











68,756TOTAL CURRENT LIABILITIES:


165,866


6,570








172,436LONG-TERM DEBT


691,896











691,896DEFERRED INCOME TAXES


16,607











16,607COMMODITY AND INTEREST DERIVATIVES


87,224











87,224ASSET RETIREMENT OBLIGATIONS


40,587


10,317


816





51,720INTERCOMPANY PAYABLES (RECEIVABLES)


48,714


(11,705
)

(37,009
)




TOTAL LIABILITIES


1,050,894


5,182


(36,193
)




1,019,883TOTAL STOCKHOLDERS' EQUITY


245,602


393,526


37,557


(431,083
)

245,602TOTAL LIABILITIES AND
STOCKHOLDERS' EQUITY

$
1,296,496

$
398,708

$
1,364

$
(431,083
)
$
1,265,485


26

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Table of Contents

CONDENSED CONSOLIDATING BALANCE SHEETS        AT SEPTEMBER 30, 2008 (Unaudited)        (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-
Guarantor
Subsidiary

Eliminations

ConsolidatedASSETSCURRENT ASSETS:Cash and cash equivalents

$
4,539

$
1

$


$


$
4,540Accounts receivable


41,783


16,115


203





58,101Inventories


4,011


7,180








11,191Prepaid expenses and other current assets


6,256











6,256Income taxes receivable


6,325











6,325Deferred income taxes


28,906











28,906Commodity derivatives


10,805











10,805TOTAL CURRENT ASSETS


102,625


23,296


203





126,124PROPERTY, PLANT & EQUIPMENT, NET


871,689


390,776


1,216





1,263,681COMMODITY DERIVATIVES


4,619











4,619INVESTMENTS IN AFFILIATES


499,578








(499,578
)

DEFERRED INCOME TAXES














OTHER


9,806


725








10,531TOTAL ASSETS

$
1,488,317

$
414,797

$
1,419

$
(499,578
)
$
1,404,955LIABILITIES AND
STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities

$
51,416

$
9,010

$


$


$
60,426Undistributed revenue payable


13,769


(839
)







12,930Interest payable


9,209











9,209Current maturities of long-term debt


2,518











2,518Commodity and interest derivatives


89,492











89,492TOTAL CURRENT LIABILITIES:


166,404


8,171








174,575LONG-TERM DEBT


752,765











752,765DEFERRED INCOME TAXES


37,860











37,860COMMODITY AND INTEREST DERIVATIVES


106,137











106,137ASSET RETIREMENT OBLIGATIONS


45,824


11,161


863





57,848INTERCOMPANY PAYABLES (RECEIVABLES)


103,557


(62,171
)

(41,386
)




TOTAL LIABILITIES


1,212,547


(42,839
)

(40,523
)




1,129,185TOTAL STOCKHOLDERS' EQUITY


275,770


457,636


41,942


(499,578
)

275,770TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
1,488,317

$
414,797

$
1,419

$
(499,578
)
$
1,404,955


27

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Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS        NINE MONTHS ENDED SEPTEMBER 30, 2007 (Unaudited)        (in thousands)

Venoco, Inc.

Guarantor Subsidiaries

Non-Guarantor Subsidiary

Eliminations

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

$
80,301

$
32,895

$
2,865

$


$
116,061CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for oil and natural gas properties


(102,992
)

(137,386
)

(27
)




(240,405
)Acquisitions of oil and natural gas properties


(120,424
)










(120,424
)Expenditures for property and equipment and other


(4,594
)

(281
)







(4,875
)Net cash provided by (used in) investing activities


(228,010
)

(137,667
)

(27
)




(365,704
)CASH FLOWS FROM FINANCING ACTIVITIES:Net proceeds from (repayments of) intercompany borrowings


(94,252
)

97,108


(2,856
)




Proceeds from long-term debt


725,421











725,421Principal payments on long-term debt


(598,516
)










(598,516
)Premium to retire debt


(3,489
)










(3,489
)Proceeds from derivative premium financing


1,676











1,676Deferred loan costs


(4,838
)










(4,838
)Proceeds from issuance of common stock


116,595











116,595Stock issuance costs


(561
)










(561
)Proceeds from exercise of stock options


3,695











3,695Excess income tax benefits from share-based compensation


2,114











2,114Net cash provided by (used in) financing activities


147,845


97,108


(2,856
)




242,097Net increase (decrease) in cash and cash equivalents


136


(7,664
)

(18
)




(7,546
)Cash and cash equivalents, beginning of period


(12
)

8,358


18





8,364Cash and cash equivalents, end of period

$
124

$
694

$


$


$
818


28

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Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS        NINE MONTHS ENDED SEPTEMBER 30, 2008 (Unaudited)        (in thousands)

Venoco, Inc.

Guarantor Subsidiaries

Non-Guarantor Subsidiary

Eliminations

ConsolidatedCASH FLOWS FROM OPERATING ACTIVITIES:Net cash provided by operating activities

$
113,692

$
59,451

$
2,718

$


$
175,861CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for oil and natural gas properties


(198,849
)

(33,873
)

13





(232,709
)Acquisitions of oil and natural gas properties


(7,976
)

(2,045
)







(10,021
)Expenditures for property and equipment and other


(3,549
)

(42
)







(3,591
)Net cash provided by (used in) investing activities


(210,374
)

(35,960
)

13





(246,321
)CASH FLOWS FROM FINANCING ACTIVITIES:Net proceeds from (repayments of) intercompany borrowings


27,194


(24,463
)

(2,731
)




Proceeds from long-term debt


225,000











225,000Principal payments on long-term debt


(169,524
)










(169,524
)Deferred loan costs


(828
)










(828
)Proceeds from derivative premium financing


7,817











7,817Stock issuance costs


(5
)










(5
)Proceeds from exercise of stock options


2,805











2,805Net cash provided by (used in) financing activities


92,459


(24,463
)

(2,731
)




65,265Net increase (decrease) in cash and cash equivalents


(4,223
)

(972
)







(5,195
)Cash and cash equivalents, beginning of period


8,762


973








9,735Cash and cash equivalents, end of period

$
4,539

$
1

$


$


$
4,540


29

---





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, 2007 as well as with the financial statements and related notes and the
other information appearing elsewhere in this report. As used in this report, unless the context otherwise indicates, references to "we," "our," "ours," and "us" refer to Venoco, Inc. and its
subsidiaries collectively.

Overview

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural
gas properties. Our strategy is to grow through exploration, exploitation and development projects we believe to be relatively low risk
and through selective acquisitions of underdeveloped properties. Our average net production was 21,949 BOE/d in the third quarter of 2008, compared to 21,033 BOE/d in the second quarter
of 2008 and 20,701 BOE/d in the third quarter of 2007.

In
the execution of our strategy, our management is principally focused on increasing our reserves of oil and natural gas and on increasing annual production through development,
exploitation and exploration activities and acquisitions. Our management is also focused on the risks and opportunities associated with current oil and natural gas prices, which remain high compared
to longer-term historical averages, and on the goal of maximizing production rates while operating in a safe manner.

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 2008 is $300.0 million, of which approximately $210.4 million (excluding changes in accrued capital
expenditures) was expended in the first nine months of 2008. We expect to spend approximately 55% of the budgeted amount on projects in the Sacramento Basin, 22% in Southern California and 15% in
Texas, with the remaining 8% going towards exploration projects in a variety of areas. Our 2009 development, exploitation and exploration capital expenditure budget is $300 million, of which
approximately 50% is expected to be deployed in the Sacramento Basin, 19% in Southern California and 4% in Texas, with the remainder going towards exploration 17% and leasehold and capitalized general
and administrative expenses 10%. We have a significant inventory of projects and should market conditions become more favorable we could potentially look to increase our capital spending later in
2009.

The
aggregate levels of capital expenditures for the remainder of 2008 and 2009, and the allocation of those expenditures, are dependent on a variety of factors, including the
availability of capital resources to fund the expenditures and changes in our business assessments as to where our capital can be most profitably employed. Accordingly, the actual levels of capital
expenditures and the allocation of those expenditures may vary materially from our estimates. The following summarizes certain significant aspects of our 2008 capital spending program and the outlook
for 2009:

Southern CaliforniaExploitation and Development

Our primary focus in Southern California in 2008 is on development activities in the West Montalvo field, where we are continuing an
aggressive workover, recompletion and return to production program that we began when we acquired the field in May 2007. We worked over six wells

30

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Table of Contents

and
returned seven wells to production during the first nine months of the year and plan to return an additional two wells to production during the fourth quarter. We also plan to drill three new
development wells in the field during the year. We spud the first of these wells in late September, the second in October, and anticipate spudding the third well in November. We plan to drill three
additional infill wells on the onshore portion of the field in 2009.

In
the Sockeye field, we continue to implement our waterflood program from platform Gail and are working on the evaluation and design of a possible expansion of the program. During the
first nine months of the year, we redrilled one well as an injector and performed four successful workovers in the field. We also continue to develop our plans for additional infill development
drilling, waterflood expansion and natural gas production. We are also planning to fracture a Monterey well at Sockeye in 2009.

In
the South Ellwood field, the permitting process continues for our full-field development project. We received the draft environmental impact report for this project from
the California State Lands Commission in June. We have provided comments on the report and are now focused on the project approval hearings which we expect to commence during either the fourth quarter
of 2008 or first quarter of 2009. Key components of the project include an extension of our current lease area (which would effectively double the size of the existing lease area) and the installation
of an onshore oil transport pipeline to replace the existing barge. Development of the extended lease area can be accomplished from the field's existing platform. We have been working on the pipeline
permitting process and right-of-way for the pipeline in 2008 and our 2009 budget includes expenditures for certain long-lead items for the full-field development project in
anticipation of regulatory approvals.

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 currently have
five drilling rigs and five
workover/completion rigs working in the basin and expect to drill approximately 120 new wells and perform more than 125 workovers and recompletions there during 2008. In the first nine
months of 2008, we spudded 84 wells, completed 61 wells, and performed 98 workovers and recompletions in the basin.

We
also continue to pursue our hydraulic fracturing program in the basin, a program that could potentially enhance production and reserves significantly. We initiated the program in
November 2007 and have fractured 47 wells during the first nine months of 2008. We are encouraged by the early success of the program and continue to analyze results in order to optimize
future fracture stimulations in the basin. We plan to fracture approximately 75 wells in the basin during 2008. Our 2009 budget will generate similar drilling, workover and fracturing
activity next year.

TexasExploitation and Development

In Texas, our focus in 2008 is on the continuation of our workover and recompletion programs in the Hastings complex and the Manvel
field. During the first nine months of the year, we performed 83 workovers and recompletions and converted 14 wells into injectors at the Hastings complex. We are also focused on
lowering operating expenses in the Hastings complex as we reduce our remediation and redevelopment activities there. At Manvel, we performed seven workovers and converted one well to an injector
during the first nine months of the year. During the fourth quarter, we plan to continue our redevelopment work at Hastings and Manvel and to drill up to three new development wells in our
Texas fields, including two at Manvel. Our 2009 budget includes capital for four new development wells, including two at Manvel.

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Exploration Activities

During the first nine months of the year we've drilled, or started drilling, two higher impact exploration wells in Texas and six in
the Sacramento Basin. We plan to drill a total of ten higher impact exploration wells during 2008.

Acquisitions and Divestitures

West Montalvo and Manvel Acquisitions.We acquired the West Montalvo field in Ventura County, California in May 2007 for $61.3 million. We acquired
the Manvel field in Brazoria County, Texas, and certain other fields in Texas, in April 2007 for $44.5 million.

Hastings Complex Sale.In November 2006, we entered into an agreement with a subsidiary of Denbury Resources Inc. pursuant to which Denbury has an
option to acquire the majority of our properties in the Hastings complex for use in a proposed CO2 enhanced recovery project in which we will have a continuing interest. On
August 29, 2008, we entered into an amendment to the agreement pursuant to which Denbury exercised its option to acquire the properties effective January 1, 2009. Denbury will either
purchase the properties or, if we so elect, enter into a volumetric production payment or similar arrangement with us with respect to the properties. Unless we and Denbury agree otherwise, the
purchase price or volumetric production payment will be based on the value of the properties as of December 31, 2008 determined with reference to the net proved reserves associated with the
properties based on then-existing operations and NYMEX forward strip pricing, subject to certain adjustments.

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.

Certain Trends Affecting our Results of Operations

Expected Production.We expect that the continued execution of our capital expenditure program will result in increases in our average net production from each of
our operating areas over the remainder
of 2008. In Southern California, we expect to achieve production increases from the drilling and workover/recompletion programs we began in the West Montalvo field in 2007 and the workover program we
began this year on Platform Gail in the Sockeye field. In the Sacramento Basin, we are continuing our multi-year drilling program and our hydraulic fracturing program and anticipate
production increases from both. We continue to assess and develop plans for a further expansion of our activities in the area. We also expect production to increase in the Hastings complex as a result
of the enhancement of our water processing and injection capabilities and the continuation of our workover and recompletion program. At the Manvel field, we are implementing a similar redevelopment
program to increase production by upgrading our fluid handling and injection capacity and performing workovers and recompletions. In 2009, the sale of our producing properties in the Hastings complex
in the first quarter will impact our overall production levels. Excluding 2008 production from those properties, however, we expect to grow production in 2009 relative to 2008, primarily as a result
of the continued development of the projects described above. Our expectations with respect to future production rates are subject to a number of uncertainties, including those associated with third
party services, oil and natural gas prices, events resulting in unexpected downtime, permitting issues, drilling success rates, pipeline capacity, and other factors, including those referenced in
"Risk Factors."

Commodity Prices.Oil and natural gas prices for the first nine months of 2008 have generally been higher than the comparable period in 2007, which has contributed
to significant increases in our oil and natural gas sales in the first nine months of 2008. Rising commodity prices have also caused us

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to
incur unrealized commodity derivative losses in the first nine months of 2008. However, commodity prices have declined substantially since June 30, 2008, which has caused us to recognize
significant unrealized commodity derivative gains in the third quarter of 2008. These unrealized gains and losses resulted 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 and 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. As a result of volatility in oil and natural gas
prices, we will likely continue to experience significant unrealized commodity derivative gains and losses. Changes in oil and natural gas prices will also continue to affect our oil and natural gas
sales, and those prices will also be a significant factor in determining the proceeds we receive in the sale of the Hastings properties. Oil and natural gas prices are affected by many factors outside
of our control, including changes in worldwide supply and demand, and we cannot predict future changes in those prices.

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, 2007 and 2008.

Three Months Ended September 30,

Nine Months Ended September 30,2007

2008

2007

2008Production Volume:Oil (MBbls)(1)


1,071


1,036


2,960


2,995Natural gas (MMcf)


5,001


5,900


13,926


17,110MBOE


1,905


2,019


5,281


5,846Daily Average Production Volume:Oil (Bbls/d)


11,641


11,261


10,842


10,931Natural gas (Mcf/d)


54,359


64,130


51,011


62,445BOE/d


20,701


21,949


19,344


21,339Oil Price per Bbl Produced (in dollars):Realized price

$
66.73

$
109.08

$
58.00

$
104.81Realized commodity derivative gain (loss) and amortization of commodity derivative premiums


(2.91
)

(32.08
)

(0.99
)

(29.69
)Net realized price

$
63.82

$
77.00

$
57.01

$
75.12Natural Gas Price per Mcf (in dollars):Realized price

$
5.71

$
8.92

$
6.56

$
9.07Realized commodity derivative loss and amortization of commodity derivative premiums


0.73


(0.15
)

0.25


(0.08
)Net realized price

$
6.44

$
8.77

$
6.81

$
8.99MBOE Sales Volume(2)


1,889


1,932


5,296


5,802Average Sales Price per BOE(3)

$
50.90

$
63.53

$
48.44

$
63.34


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Three Months Ended September 30,

Nine Months Ended September 30,2007

2008

2007

2008Expense per BOE:Production expenses(4)

$
14.90

$
21.01

$
15.04

$
18.40Transportation expenses


0.60


0.82


0.84


0.74Depreciation, depletion and amortization


13.32


16.31


13.17


16.09General and administrative expense(5)


4.00


5.07


4.67


5.38Interest expense


8.13


6.59


8.44


7.02


---

Comparison of Quarter Ended September 30, 2008 to Quarter Ended September 30, 2007

Oil and Natural Gas Sales.Oil and natural gas sales increased $62.3 million (65%) to $158.0 million for the quarter ended September 30, 2008
from $95.7 million for the same period in 2007. The increase was primarily due to a 25% increase in average sales prices and a 6% increase in production as described below.

Oil
sales increased by $37.8 million (56%) in the third quarter of 2008 to $105.4 million compared to $67.6 million in the third quarter of 2007. Oil production
decreased by 3%, with production of 1,036 MBbl in the third quarter of 2008 compared to 1,071 MBbl in the third quarter of 2007. The production decrease was primarily related to
curtailed production at the South Ellwood field due to an interruption in barge service. The barge that transports the oil produced from the field was out of service for scheduled repairs for the
majority of August and all of September. In addition, the Hastings complex and the Manvel field were shut in for seven to ten days due to Hurricane Ike in September. Our average realized price for oil
increased $42.35 (63%) to $109.08 per Bbl for the period.

Natural
gas sales increased $24.5 million (87%) in the third quarter of 2008 to $52.6 million compared to $28.1 million in the third quarter of 2007. Natural gas
production increased 18%, with production of 5,900 MMcf in the third quarter of 2008 compared to 5,001 MMcf in the third quarter of 2007. The increase was due primarily to drilling,
recompletion and hydraulic fracturing activities in the Sacramento Basin. Our average realized price for natural gas increased $3.21 (56%) to $8.92 per Mcf for the period.

Other Revenues.Other revenue remained relatively constant at $1.1 million in the third quarter of 2008 compared to $1.0 million in the third quarter
of 2007.

Production Expenses.Production expenses, which consist of lease operating expenses ("LOE") and production/property taxes, increased $14.0 million (49%) to
$42.4 million in the third quarter of

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2008
from $28.4 million in the third quarter of 2007. The increase was primarily due to non-recurring maintenance costs related to certain wells in the Sockeye field, a significant
increase in electricity usage and rates in Texas, and an increase in the number of producing wells at other properties. Also contributing to the overall increase in production expenses was an increase
in secured and supplemental property taxes related to our California properties. On a per unit basis, LOE increased to $17.89 per BOE in the third quarter of 2008 from $13.73 per BOE in the same
period in 2007.

Transportation Expenses.Transportation expenses increased $0.6 million (45%) to $1.7 million in the third quarter of 2008 from $1.1 million
in the third quarter of 2007. On a per BOE basis, transportation expenses increased $0.22 per BOE, from $0.60 per BOE in the third quarter of 2007 to $0.82 per BOE in the third quarter of 2008. The
increase is primarily related to maintenance costs incurred in the third quarter of 2008 on the barge that delivers the South Ellwood oil production.

Depletion, Depreciation and Amortization (DD&A).DD&A expense increased $7.5 million (30%) to $32.9 million in the third quarter of 2008 from
$25.4 million in the third quarter of 2007. DD&A expense rose $2.99 per BOE, from $13.32 per BOE in the third quarter of 2007 to $16.31 per BOE in the third quarter of 2008. The increase was
primarily due to a higher depletion expense based on an increase in our oil and natural gas property cost resulting from our capital expenditure program.

Accretion of Abandonment Liability.Accretion expense was $1.0 million in the third quarter of 2008 compared to $0.9 million in the third quarter of
2007. The increase was due to accretion from new wells drilled and completed in 2007 and the first nine months of 2008.

General and Administrative (G&A).G&A expense increased $2.6 million (34%) to $10.2 million in the third quarter of 2008 from $7.6 million in
the third quarter of 2007. The increase primarily resulted from an increase in our professional staff and related infrastructure. Non-cash SFAS 123R compensation expense charged to
G&A decreased $0.1 million (6%) from $1.2 million in 2007 to $1.1 million in 2008 as a result of the settlement of an employment contract in the third quarter of 2007. Excluding
the effect of the non-cash SFAS 123R compensation expense charges, G&A expense increased $1.13 from $3.37 per BOE in the third quarter of 2007 to $4.50 per BOE in the third quarter of 2008.

Interest Expense, Net.Interest expense, net of interest income, decreased $2.2 million (14%) from $15.5 million in the third quarter of 2007 to
$13.3 million in the third quarter of 2008. The decrease was primarily the result of lower interest rates realized during the third quarter of 2008, partially offset by an increase in average
debt outstanding.

Amortization of Deferred Loan Costs.Amortization of deferred loan costs decreased $0.3 million, from $1.0 million in the third quarter of 2007 to
$0.7 million in the third quarter of 2008. The decrease was primarily due to the amendment to the revolving credit facility in May 2008 which extended the maturity date of
the facility.

Interest Rate Derivative Losses (Gains), Net.Changes in the fair value of our interest rate swap derivative instruments resulted in unrealized gains of
$0.6 million in the third quarter of 2008 and a loss of
$8.3 million in the 2007 period. The change between periods is the result of an increase in estimated interest rates used to determine the fair value of the derivative instruments at September
30, 2008 and a decrease in estimated interest rates in the third quarter of 2007. Realized interest rate swap losses were $3.4 million in the third quarter of 2008 compared to nil in the third
quarter of 2007.

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

Three Months Ended September 30,2007

2008Realized commodity derivative (gains) losses

$
(530
)
$
34,095Unrealized commodity derivative (gains) losses


8,576


(338,773
)Amortization of derivative premiums


1,650


1,626Total

$
9,696

$
(303,052
)


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 losses in the third quarter of 2008 reflect the settlement of contracts at prices above the relevant strike prices, while the realized derivative gain in the third
quarter of 2007 reflects 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. The change in unrealized commodity derivative (gains) losses reflects an increase in the notional volumes under derivative contracts outstanding in the 2008
period and a decrease in the futures prices used to estimate the fair value of those contracts at the end of the period. Derivative premiums are amortized over the term of the underlying derivative
contracts.

Income Tax Expense (Benefit).The net income in the third quarter of 2008 resulted in income tax expense of $136.2 million compared to the income tax
benefit of $1.7 million for the third quarter of 2007.

Net Income (Loss).Net income for the third quarter of 2008 was $220.9 million compared to net income of $0.5 million for the same period in 2007.
The change between periods is the result of the items discussed above.

Comparison of Nine Months Ended September 30, 2008 to Nine Months Ended September 30, 2007

Oil and Natural Gas Sales.Oil and natural gas sales increased $202.8 million (78%) to $461.8 million for the nine months ended September 30,
2008 from $259.0 million for the same period in 2007. The increase was primarily due to a 31% increase in average sales prices and an 11% increase in production, as further described below.

Oil
sales increased by $138.3 million (82%) in the first nine months of 2008 to $306.7 million from $168.4 million in the first nine months of 2007. Oil production
rose 1%, with production of 2,995 MBbl in the first nine months of 2008 compared to 2,960 MBbl in the first nine months of 2007. The production increase was attributable primarily to the
effect of a full period of production from the Manvel field, which was purchased in April 2007, and from the West Montalvo field, which was purchased in May 2007. The increase was
substantially offset by reduced production from the South Ellwood field as a result of an interruption in barge service for scheduled repairs during the majority of August and all of
September 2008. In addition, the Hastings and Manvel fields were shut in for seven to ten days as a result of Hurricane Ike in the third quarter of 2008. Our average realized price for oil
increased $46.81 (81%) to $104.81 per Bbl for the period.

Natural
gas sales increased $64.4 million (71%) in the first nine months of 2008 to $155.1 million compared to $90.7 million in the first nine months of 2007.
Natural gas production increased 23%, with production of 17,110 MMcf compared to 13,926 MMcf in the first nine months of 2007. The increase

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was
due primarily to drilling, recompletion and hydraulic fracturing activities in the Sacramento Basin. Our average realized price for natural gas increased $2.51 (38%) to $9.07 per Mcf for
the period.

Other Revenues.Other revenue remained relatively flat at $2.8 million in the first nine months of 2008 compared to $2.6 million in the first nine
months of 2007.

Production Expenses.Production expenses, which consist of lease operating expenses ("LOE") and production/property taxes, increased $28.2 million (35%) to
$107.6 million in the first nine months of 2008 from $79.4 million in the first nine months of 2007. The increase was due to (i) a significant increase in electricity usage and
rates in Texas in the third quarter of 2008, (ii) non-recurring maintenance costs incurred at Sockeye in 2008, (iii) the effect of a full nine months of expense related to
the Manvel and Montalvo acquisitions, which occurred in April and May 2007, respectively, and (iv) an increase in secured and supplemental property taxes related to our California
properties. On a per unit basis, LOE increased to $16.03 per BOE in the first nine months of 2008 compared to $13.90 per BOE in the same period in 2007.

Transportation Expenses.Transportation expenses remained relatively flat at $4.3 million for the first nine months of 2008 compared to $4.4 million
for the first nine months of 2007. On a per BOE basis, transportation expenses decreased $0.10 per BOE, from $0.84 per BOE in the first nine months of 2007 to $0.74 per BOE in the first nine months of
2008.

Depletion, Depreciation and Amortization (DD&A).DD&A expense increased $24.5 million (35%) to $94.0 million in the first nine months of 2008 from
$69.5 million in the first nine months of 2007. DD&A expense per BOE rose $2.92, from $13.17 per BOE in the first nine months of 2007 to $16.09 per BOE in the first nine months of 2008. The
increase was primarily due to a higher depletion expense based on an increase in the oil and natural gas property costs resulting from our capital expenditure program.

Accretion of Asset Retirement Obligations.Accretion expense was $3.1 million in the first nine months of 2008 compared to $2.5 million in the first
nine months of 2007. The increase was primarily due to accretion from new wells drilled and completed in 2007 and the first nine months of 2008.

General and Administrative (G&A).G&A expense, net of amounts capitalized, increased $6.8 million (28%) to $31.5 million in the first nine months of
2008 from $24.7 million in the first nine months of 2007. The increase was a result of costs of $2.7 million that were expensed in the second quarter of 2008 in connection with the
cancellation of a planned master limited partnership ("MLP") offering, as
well as an increase in our professional staff and related infrastructure. Non-cash SFAS 123R share-based compensation expense for the first nine months of 2007 was
$3.7 million, compared to $3.4 million in the first nine months of 2008. The decrease was primarily due to the settlement of multiple employment agreements during the first nine months
of 2007. Excluding the effect of the non-cash SFAS 123R charges and the non-recurring MLP charges, G&A increased $0.37 per BOE from $3.97 per BOE for the first nine months of 2007 to $4.34 for
the first nine months of 2008.

Interest Expense, Net.Interest expense, net of interest income, decreased $3.5 million (8%) from $44.6 million in the first nine months of 2007 to
$41.1 million in the first nine months of 2008, primarily as a result of a decrease in interest rates during the first nine months of 2008, partially offset by an increase in average debt
outstanding.

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Amortization of Deferred Loan Costs.Amortization of deferred loan costs decreased $0.6 million (18%) from $3.2 million in the first nine months of
2007 to $2.6 million in the first nine months of 2008. The decrease was primarily due to the write-off of deferred loan costs in connection with the refinancing of our term loan
facility in the first nine months of 2007, as well as the amendment to the revolving credit facility in May 2008 which extended the maturity date of the facility.

Interest Rate Derivative Losses (Gains), Net.Changes in the fair value of our interest rate swap derivative instruments resulted in an unrealized gain of
$0.3 million in the first nine months of 2008 and an unrealized loss of $8.5 million in the first nine months of 2007. The change between periods is the result of an increase in the
notional amount of debt covered by the interest rate swap, an increase in estimated interest rates used to determine the fair value of the derivative instruments at September 30, 2008 and a
decrease in estimated interest rates in the third quarter of 2007. Realized interest rate swap losses were $7.1 million in the first nine months of 2008 compared to $0.1 million in the
first nine months of 2007.

Loss on Extinguishment of Debt.We incurred a loss on extinguishment of debt of $12.1 million in the first
nine months of 2007 when we prepaid our original second lien term loan facility and replaced it with our current term loan facility. We paid a premium of $3.5 million and wrote off related
deferred loan costs of $8.6 million in connection with the prepayment.

Commodity Derivative 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 30,2007

2008Realized commodity derivative (gains) losses

$
(554
)
$
90,214Unrealized commodity derivative (gains) losses


31,428


40,998Amortization of derivative premiums


5,179


5,155Total

$
36,053

$
136,367


Realized
commodity derivative gains or losses represent the difference between the strike price in the contracts settled during the period and the ultimate settlement prices. The
realized commodity derivative gains in the 2007 period reflect the settlement of contracts at prices below the strike price, whereas the realized commodity derivative losses in the 2008 period reflect
the settlement of contracts at prices above the strike price. Unrealized commodity derivative (gains) losses represent the change in the fair value of our open derivative contracts from period to
period. The change in unrealized commodity derivative losses reflects an increase in the notional volumes under derivative contracts outstanding in the 2008 period as well as an increase in the
futures prices used to estimate the fair value of those contracts at the end of the period. Derivative premiums are amortized over the term of the underlying derivative contracts.

Income Tax Expense (Benefit).The income before taxes in the first nine months of 2008 resulted in an income tax expense of $14.4 million whereas the loss
before income taxes in the first nine months of 2007 resulted in an income tax benefit of $10.4 million.

Net Income (Loss).Net income for the first nine months of 2008 was $22.9 million compared to a net loss of $13.0 million for the same period in
2007. 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 30,2007

2008(in thousands)Cash provided by operating activities

$
116,061

$
175,861Cash used in investing activities


(365,704
)

(246,321
)Cash provided by financing activities


242,097


65,265


Net
cash provided by operating activities was $175.9 million in the first nine months of 2008 compared with $116.1 million in the first nine months of 2007. Cash flows from
operating activities in the first nine months of 2008 were favorably impacted by increases in commodity prices, production from properties acquired and our development program. Cash flows from
operating activities were unfavorably impacted in the first nine months of 2008 by premiums paid for derivative contracts.

Net
cash used in investing activities was $246.3 million in the first nine months of 2008 compared with $365.7 million in the first nine months of 2007. The primary
investing activities in the first nine months of 2008 include $242.7 million in capital expenditures on oil and natural gas properties related to our 2008 capital expenditure program. The
primary investing activities in the first nine months of 2007 include $240.4 million in capital expenditures on oil and gas properties and $120.4 million paid for acquisitions, including
the West Montalvo and Manvel fields.

Net
cash provided by financing activities was $65.3 million in the first nine months of 2008 compared to $242.1 million in the first nine months of 2007. The primary
financing activities in the first nine months of 2008 were $58.0 million in net borrowings under our revolving credit facility to fund capital expenditures and working capital needs. Financing
activities in the first nine months of 2007 included $151.1 million in net borrowings under the second lien term loan facility and $20.6 million in net borrowings under the revolving
credit facility to fund acquisitions, capital expenditures and working capital needs. Net proceeds from an additional offering of common stock completed in July 2007 were
$116.0 million, of which $95.0 million was used to reduce amounts outstanding under our revolving credit facility.

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 $210.4 million in the first nine months of 2008, will be approximately
$300.0 million for the year. We currently expect that our exploration, exploitation and development capital expenditures in 2009 will also be approximately $300.0 million. We intend to
finance our capital expenditures for the remainder of 2008 primarily with cash flow from operations before working capital adjustments and amounts borrowed under our revolving credit facility. We
expect to finance our capital expenditures for 2009 primarily with cash flow from operations before working capital adjustments, amounts borrowed under our revolving credit
facility and proceeds from the sale of our interest in part of the Hastings complex. As of November 5, 2008, we had $79.8 million (net of $1.2 million in outstanding letters of
credit and $4.75 million attributable to Lehman Commercial Papersee below) in effective unused borrowing capacity under the revolving credit facility.

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Uncertainties
relating to our capital resources and requirements in 2008 and 2009 include the possibility that we will pursue one or more significant acquisitions that would require
additional debt or equity financing. Additional uncertainties relate to the sale of our producing properties in the Hastings complex. These uncertainties include the magnitude of the actual proceeds
received from the sale and the potential exercise of our option to enter into a volumetric production payment or similar arrangement with Denbury in lieu of accepting cash proceeds in the sale. If we
elect to receive cash in the sale, the consideration we would receive would be a significant additional source of liquidity, subject to mandatory repayment requirements of a portion of the proceeds
under our credit facilities. Election of the volumetric production payment option would have a smaller immediate impact on our liquidity, but would provide additional liquidity over a period expected
to be approximately ten years. The election of the volumetric production payment option would also have an effect on the required use of proceeds under the second lien term loan.

Amended Revolving Credit Facility.We entered into a second amended and restated agreement governing our revolving credit facility in March 2006, and have
entered into several subsequent amendments to the agreement. In May 2008 we amended the facility to, among other things, extend its maturity to March 2011. The agreement contains
customary representations, warranties, events of default, indemnities and covenants, including covenants that restrict our ability to incur indebtedness and require us to maintain specified ratios of
current assets to current liabilities and debt to EBITDA (as defined in the agreement). The borrowing base is subject to redetermination in April and November of each year. 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 Bank of Montreal's announced base rate and
the overnight federal funds rate plus 0.50% plus (ii) an applicable margin ranging from zero to 0.75%, based upon utilization. Loans designated as "LIBO Rate Loans" under the revolving credit
facility bear interest at (i) LIBOR plus (ii) an applicable margin ranging from 1.50% to 2.25%, based upon utilization. A commitment fee ranging from 0.375% to 0.5% per annum is payable
with respect to unused borrowing availability under the facility.

The
borrowing base under our revolving credit facility is currently $200.0 million and has been allocated at various percentages to a syndicate of 12 banks. Certain of the
institutions included in the syndicate have received support from governmental agencies in connection with recent events in the credit markets. In addition, 4.75% of the $200.0 million
borrowing base has been allocated to Lehman Commercial Paper ("LCP"), a wholly-owned subsidiary of Lehman Brothers Holding, Inc., which filed for bankruptcy protection on September 15,
2008. LCP is no longer funding its portion of our borrowing requests made under the facility. As of November 5, 2008, we owed LCP $4.75 million. Our effective borrowing base is
$195.25 million, excluding $4.75 million related to LCP. A failure of any other member of the syndicate to fund under the facility, or a reduction in the borrowing base, would adversely
affect our liquidity.

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 covenants, including covenants that restrict our ability to incur additional indebtedness. The agreement
requires us to maintain derivative contracts covering at least 70% of our projected oil and natural gas production attributable to proved developed producing reserves through May 8, 2010, and
at least 50% of such production on an annual basis thereafter. 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

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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.

Loans
under the 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%. We have entered into interest rate swaps pursuant to which
amounts borrowed under the new term loan agreement will effectively bear interest at a fixed rate of approximately 9.3% until June 2010. See "Quantitative and Qualitative
Disclosures About Market RiskInterest Rate Derivative Transactions."

Senior Notes.We issued $150.0 million of our senior notes in December 2004. The notes bear interest at 8.75% per year and will mature on
December 15, 2011. We may redeem the notes after December 15, 2008, initially at a redemption price equal to 104.375% of the principal amount. In addition, before December 15,
2008, we may redeem all or part of the notes at a specified "make-whole" price. Upon the occurrence of a change of control of our company, each holder of the notes may require us to
repurchase all or a portion of its notes for cash at a price equal to 101% of the aggregate
principal amount of those notes, plus any accrued and unpaid interest. The indenture governing the notes also contains operational covenants that, among other things, limit our ability to make
investments, incur additional indebtedness or create liens on our assets. The notes are secured with the second lien term loan on an equal and ratable basis.

Because
we must dedicate a substantial portion of our cash flow from operations to the payment of interest on our debt, 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, 2008, we had no existing off-balance sheet arrangements, as defined under SEC rules, that have or
are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

This section provides information about derivative financial instruments we use to manage commodity price volatility. Due to the
historical volatility of crude oil and natural gas prices, we have implemented a 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

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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.

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

Commodity Derivative Transactions

Oil.As of September 30, 2008, we had entered into derivative agreements to receive average minimum and maximum NYMEX West Texas Intermediate prices as
summarized below. Location and quality differentials attributable to our properties are not reflected in those prices. The agreements provide for monthly settlement based on the differential between
the agreement price and the actual NYMEX crude oil price.

Minimum

MaximumBbls/d

Weighted Avg.
Prices

Bbls/d

Weighted Avg.
PricesCrude oil derivatives at September 30, 2008 for production:October 1December 31, 2008


8,100

$
59.20


8,100

$
73.65January 1December 31, 2009


6,983

$
58.09


6,983

$
74.38January 1December 31, 2010


6,150

$
61.10


6,150

$
72.88January 1December 31, 2011


7,000

$
70.00


7,000

$
141.64


Natural Gas.As of September 30, 2008, we had entered into derivative agreements to receive average minimum and maximum NYMEX or PG&E Citygate prices
as follows:

Minimum

MaximumMMBtu/d

Weighted Avg.
Prices

MMBtu/d

Weighted Avg.
PricesNatural gas derivatives at September 30, 2008 for production:October 1December 31, 2008


32,650

$
7.67


31,032

$
11.47January 1December 31, 2009


33,125

$
7.87


23,125

$
11.42January 1December 31, 2010


17,900

$
7.32


17,900

$
11.03January 1December 31, 2011


12,000

$
7.50


12,000

$
13.50


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Table of Contents

Portfolio of Derivative Transactions

Our portfolio of commodity derivative transactions as of September 30, 2008 is summarized below:

Oil

Type of Contract

Basis

Quantity
(Bbl/d)

Strike Price
($/Bbl)

TermCollar

NYMEX


2,450

$52.00/$75.00


Jul 1Dec 31, 08Collar

NYMEX


1,000

$58.00/$78.00


Jul 1Dec 31, 08Collar

NYMEX


1,500

$58.00/$75.25


Jan 1Dec 31, 08Swap

NYMEX


2,500

$67.25


Jan 1Dec 31, 08Collar

NYMEX


800

$60.00/$82.75


Jan 1Dec 31, 08Collar

NYMEX


(150
)
$60.00/$82.75


Jan 1Dec 31, 08Collar

NYMEX


2,170

$50.00/$75.00


Jan 1Jun 30, 09Collar

NYMEX


1,000

$56.00/$79.25


Jul 1Dec 31, 09Collar

NYMEX


3,000

$55.00/$77.00


Jan 1Dec 31, 09Swap

NYMEX


2,000

$67.22


Jan 1Dec 31, 09Collar

NYMEX


750

$60.00/$82.75


Jan 1Dec 31, 09Collar

NYMEX


(700
)
$60.00/$82.75


Jan 1Jun 30, 09Collar

NYMEX


1,000

$60.00/$72.80


Jan 1Dec 31, 10Collar

NYMEX


3,500

$60.00/$73.00


Jan 1Dec 31, 10Swap

NYMEX


1,000

$66.75


Jan 1Dec 31, 10Collar

NYMEX


650

$60.00/$81.75


Jan 1Dec 31, 10Collar

NYMEX


2,000

$70.00/$144.75


Jan 1Dec 31, 11Collar

NYMEX


2,000

$70.00/$141.00


Jan 1Dec 31, 11Collar

NYMEX


3,000

$70.00/$140.00


Jan 1Dec 31, 11


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Table of Contents

Natural Gas

Type of Contract

Basis

Quantity
(MMBtu/d)

Strike Price
($/MMBtu)

TermPut

NYMEX


6,000

$8.00 Floor


Jan 1Dec 31, 08Call

NYMEX


4,382

$10.60 Cap


Jul 1Dec 31, 08Collar

NYMEX


7,500

$8.00/$12.75


Jan 1Dec 31, 08Collar

NYMEX


5,700

$7.75/$10.05


Jan 1Dec 31, 08Basis Swap

PG&E Citygate


10,000

$(0.32)


Jan 1Dec 31, 08Collar

NYMEX


1,450

$8.00/$12.95


Jan 1Dec 31, 08Collar

NYMEX


12,000

$7.50/$11.75


Mar 1Dec 31, 08Swap

NYMEX


1,250

$8.72 Fixed


Jan 1Jun 30, 09Collar

NYMEX


1,250

$7.75/$13.05


Jan 1Jun 30, 09Swap

NYMEX


1,250

$8.00 Fixed


Jul 1Dec 31, 09Collar

NYMEX


1,250

$7.25/$11.30


Jul 1Dec 31, 09Collar

NYMEX


7,000

$7.50/$12.75


Jan 1Dec 31, 09Basis Swap

PG&E Citygate


6,000

$0.10


Jan 1Dec 31, 09Basis Swap

PG&E Citygate


7,500

$0.11


Jan 1Dec 31, 09Collar

NYMEX


4,000

$7.30/$9.85


Jan 1Dec 31, 09Collar

NYMEX


1,125

$8.00/$12.00


Jan 1Dec 31, 09Collar

NYMEX


8,500

$7.50/$11.15


Jan 1Dec 31, 09Put

NYMEX


10,000

$8.50 Floor


Jan 1Dec 31, 09Collar

NYMEX


10,000

$7.00/$10.35


Jan 1Dec 31, 10Basis Swap

PG&E Citygate


10,000

$0.22


Jan 1Dec 31, 10Collar

NYMEX


1,000

$7.00/$9.10


Jan 1Dec 31, 10Collar

NYMEX


900

$7.50/$12.20


Jan 1Dec 31, 10Collar

NYMEX


6,000

$7.50/$11.95


Jan 1Dec 31, 10Collar

NYMEX


12,000

$7.50/$13.50


Jan 1Dec 31, 11


We
enter into derivative contracts to hedge future crude oil and natural gas production in an effort to mitigate the risk of market price fluctuations. The objective of our hedging
activities and the use of derivative financial instruments is to achieve more predictable cash flows. Our hedging activities attempt 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 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
contract, we will be required to make payments against which there are no offsetting sales of production. This could impact our ability to fund future capital expenditures. 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 ability to fund expected capital expenditures. Finally, the use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of
such contracts.

Lehman
Brothers Commodity Services, Inc. ("LBCS") was a counterparty to several derivative contracts with us entered into between August 2006 and May 2008. On September 15,
2008, Lehman Brothers Holdings Inc, ("LBH"), credit support provider for LBCS, filed for bankruptcy. The bankruptcy filing of LBH constituted an event of default under the ISDA Master Agreement.
Accordingly, on September 18, 2008, we notified LBCS that we were terminating each of the outstanding transactions, effective immediately, which resulted in a receivable due to us of
$0.7 million. Subsequent to our notification of termination, LBCS filed for bankruptcy protection.

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Table of Contents

Because
a large portion of our commodity derivatives do not qualify for hedge accounting and to increase clarity in our financial statements, we elected to discontinue hedge accounting
effective April 1, 2007. Consequently, from that date forward, we have recognized mark-to-market gains and losses in earnings currently, rather than deferring such
amounts in accumulated other comprehensive income for those commodity derivatives that qualify as cash flow hedges.

All
derivative instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying
market price at the determination date. Changes in the fair value of derivatives are recorded in commodity derivative gains (losses) on the consolidated statement of operations. As of
September 30, 2008, the fair value of our commodity derivatives was a liability of $162.7 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. We have entered into two interest rate swap transactions to limit our exposure to changes in interest rates with respect to our second lien term loan facility. In May 2006,
we entered into a swap to lock in our interest cost on $200.0 million of borrowings through May 2008. In June 2007, we entered into a second swap to lock in our interest cost on
$300.0 million of borrowings through May 2008 and on $500.0 million of borrowings from May 2008 through June 2010. As a result of these transactions, amounts
borrowed under the second lien term loan facility will effectively bear interest at a fixed rate of approximately 9.3% until June 2010. Accordingly, we expect to be subject to interest rate
risk until that time only with respect to amounts borrowed under the revolving credit facility. As of November 5, 2008, there was approximately $114.3 million outstanding under that
facility. A 1.0% increase in interest rates on unhedged variable rate borrowings of $100.0 million at September 30, 2008 would result in additional annualized interest expense of
$1.0 million. As of September 30, 2008, the fair value of our interest rate derivatives was a liability of $17.5 million.

See
notes to our consolidated financial statements for a discussion of our long-term debt as of September 30, 2008.

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, 2008. 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, 2008 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

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, 2007, which could materially affect our business, financial condition and/or future results. The risks
described in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial
also may materially adversely affect our business, financial condition and/or operating results.

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

Not Applicable

Item 3. DEFAULTS UPON SENIOR SECURITIES

Not Applicable

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not Applicable

Item 5. OTHER INFORMATION

Not Applicable

Item 6. EXHIBITS

Exhibit Number

Exhibit10.1

Resignation and Release Agreement, dated as of October 20, 2008, by and between Mark DePuy and Venoco, Inc.10.2

Independent Contractor Agreement, dated as of November 4, 2008, by and between Mark DePuy and Venoco, Inc.31.1

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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Table of Contents

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
5, 2008

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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