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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 March 31, 2009oro

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 3900Denver, Colorado(Address of principal executive offices)

80202-1370(Zip Code)


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

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

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

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

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

Large Accelerated Filer o

Accelerated Filer ý

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

Smaller Reporting Company o


Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

YES o    NO ý

As of March 31, 2009, there were 52,402,703 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 2009, the nature, timing and
results of capital expenditure projects, amounts of future capital expenditures, our future debt levels and liquidity, the future amount of the borrowing base under our revolving credit facility and
our receipt of approvals relating to the South Ellwood full-field development project. 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, 2008. 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, 2008 and such things as:



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VENOCO, INC.
Form 10-Q for the Quarterly Period Ended March 31, 2009



TABLE OF CONTENTS



PART I.

FINANCIAL INFORMATIONItem 1.

Financial Statements (Unaudited)

2Condensed Consolidated Balance Sheets at December 31, 2008 and March 31, 2009

2Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2008 and the Three Months
Ended March 31, 2009

3Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2008 and the Three
Months Ended March 31, 2009

4Condensed Consolidated Statements of Changes in Stockholders' Equity for the Three Months Ended March 31,
2009

5Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2008 and the Three Months
Ended March 31, 2009

6Notes to Condensed Consolidated Financial Statements

7Item 2.

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

28Item 3.

Quantitative and Qualitative Disclosures about Market Risk

38Item 4.

Controls and Procedures

41PART II.

OTHER INFORMATIONItem 1.

Legal Proceedings

42Item 1A.

Risk Factors

42Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

42Item 3.

Defaults upon Senior Securities

42Item 4.

Submission of Matters to a Vote of Security Holders

42Item 5.

Other Information

42Item 6.

Exhibits

42Signatures

43


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,
2008

March 31,
2009ASSETSCURRENT ASSETS:Cash and cash equivalents

$
191

$
15,020Accounts receivable, net of allowance for doubtful accounts of $750 and $900 at December 31, 2008 and March 31, 2009, respectively


41,306


31,541Inventories


12,361


4,211Prepaid expenses and other current assets


4,314


3,856Income taxes receivable


546


Commodity derivatives


57,247


73,105Total current assets


115,965


127,733PROPERTY, PLANT AND EQUIPMENT, AT COST:Oil and natural gas properties (full cost method, of which $30,228 and $35,570 for unproved properties were excluded from amortization at December 31,
2008 and March 31, 2009, respectively)


1,671,799


1,534,372Drilling equipment


14,460


14,460Other property and equipment


22,932


22,119Total property, plant and equipment


1,709,191


1,570,951Accumulated depletion, depreciation and amortization


(1,006,457
)

(1,027,731
)Net property, plant and equipment


702,734


543,220OTHER ASSETS:Commodity derivatives


35,314


49,289Deferred loan costs


7,458


6,798Other


2,783


3,074Total other assets


45,555


59,161TOTAL ASSETS

$
864,254

$
730,114LIABILITIES AND STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities

$
75,400

$
40,607Undistributed revenue payable


8,277


9,017Interest payable


5,325


7,384Income taxes payable





8,304Current maturities of long-term debt


2,598


4,521Commodity and interest derivatives


21,284


24,204Total current liabilities


112,884


94,037LONG-TERM DEBT


797,670


660,194COMMODITY AND INTEREST DERIVATIVES


9,363


4,853ASSET RETIREMENT OBLIGATIONS


79,504


79,028Total liabilities


999,421


838,112COMMITMENTS AND CONTINGENCIESSTOCKHOLDERS' EQUITY:Common stock, $.01 par value (200,000,000 shares authorized; 51,548,990 and 52,402,703 shares issued and outstanding at December 31, 2008 and
March 31, 2009, respectively)


515


524Additional paid-in capital


319,336


320,668Retained earnings (accumulated deficit)


(453,594
)

(428,389
)Accumulated other comprehensive loss


(1,424
)

(801
)Total stockholders' equity


(135,167
)

(107,998
)TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
864,254

$
730,114


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 March 31,2008

2009REVENUES:Oil and natural gas sales

$
136,665

$
57,431Other


785


885Total revenues


137,450


58,316EXPENSES:Oil and natural gas production


32,009


26,726Transportation expense


1,297


1,046Depletion, depreciation and amortization


31,246


22,683Accretion of asset retirement obligations


993


1,357General and administrative, net of amounts capitalized


9,066


7,998Total expenses


74,611


59,810Income (loss) from operations


62,839


(1,494
)FINANCING COSTS AND OTHER:Interest expense, net


14,589


11,178Amortization of deferred loan costs


999


735Interest rate derivative losses (gains), net


13,971


947Commodity derivative losses (gains), net


74,636


(48,559
)Total financing costs and other


104,195


(35,699
)Income (loss) before income taxes


(41,356
)

34,205Income tax provision (benefit)


(15,900
)

9,000Net income (loss)

$
(25,456
)
$
25,205Earnings per common share:Basic

$
(0.51
)
$
0.49Diluted

$
(0.51
)
$
0.49Weighted average common shares outstanding:Basic


50,227


50,702Diluted


50,227


50,702


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 March 31,2008

2009Net income (loss)

$
(25,456
)
$
25,205OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:Hedging activities:Reclassification adjustments for settled contracts


180


623Other comprehensive income (loss)


180


623Comprehensive income (loss)

$
(25,276
)
$
25,828


See
notes to condensed consolidated financial statements.

4

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

Common Stock



Retained
Earnings
(Accumulated
Deficit)

Accumulated
Other
Comprehensive
Income (Loss)Additional
Paid-in
CapitalShares

Amount

TotalBALANCE AT DECEMBER 31, 2008


51,549

$
515

$
319,336

$
(453,594
)
$
(1,424
)
$
(135,167
)Comprehensive income:Reclassification adjustment for settled contracts, net of tax














623


623Issuance of restricted shares, net of cancellations


841


9


(9
)







Share-based payments








1,250








1,250Issuance of common stock pursuant to Employee Stock Purchase Plan


13





76








76Disgorgement of stock sale profits








15








15Net income











25,205





25,205BALANCE AT MARCH 31, 2009


52,403

$
524

$
320,668

$
(428,389
)
$
(801
)
$
(107,998
)


5

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

Three Months Ended
March 31,2008

2009CASH FLOWS FROM OPERATING ACTIVITIES:Net income (loss)

$
(25,456
)
$
25,205Adjustments to reconcile net income (loss) to net cash provided by operating activities:Depletion, depreciation and amortization


31,246


22,683Accretion of abandonment liability


993


1,357Deferred income taxes (benefit)


(16,000
)

Share-based compensation


787


550Amortization of deferred loan costs


999


735Amortization of bond discounts and other non-cash interest


112


178Unrealized interest rate swap derivative losses (gains)


13,554


(2,993
)Unrealized commodity derivative losses (gains) and amortization of premiums and other comprehensive loss


56,666


(17,151
)Changes in operating assets and liabilities:Accounts receivable


(11,644
)

9,765Inventories


2,127


(277
)Prepaid expenses and other current assets


(462
)

423Income taxes receivable/payable


100


8,850Other assets


746


(291
)Accounts payable and accrued liabilities


(3,241
)

(15,563
)Undistributed revenue payable


(2,061
)

(160
)Net premiums paid on derivative contracts


(8,511
)

(10,656
)Net cash provided by operating activities


39,955


22,655CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for oil and natural gas properties


(80,495
)

(68,865
)Acquisitions of oil and natural gas properties


(5,328
)

(2,664
)Proceeds from sale of oil and natural gas properties





200,060Expenditures for other property and equipment


(1,021
)

(677
)Net cash (used in) provided by investing activities


(86,844
)

127,854CASH FLOWS FROM FINANCING ACTIVITIES:Proceeds from long-term debt


60,000


57,626Principal payments on long-term debt


(10,893
)

(193,357
)Payments for deferred loan costs


(68
)

(40
)Proceeds from derivative premium financing


2,488


Proceeds from Employee Stock Purchase Plan





76Proceeds from disgorgement of stock sale profits





15Proceeds from exercise of stock options


29


Stock issuance costs


(5
)

Net cash (used in) provided by financing activities


51,551


(135,680
)Net increase (decrease) in cash and cash equivalents


4,662


14,829Cash and cash equivalents, beginning of period


9,735


191Cash and cash equivalents, end of period

$
14,397

$
15,020Supplemental Disclosure of Cash Flow InformationCash paid for interest

$
12,453

$
8,968Cash paid for income taxes

$


$
150Supplemental Disclosure of Non-cash ActivitiesAccrued capital expenditures at period end

$
24,884

$
13,032Increase (decrease) in accrued capital expenditures

$
17,796

$
(17,171
)


See notes to condensed consolidated financial statements.

6

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

1. SIGNIFICANT ACCOUNTING POLICIES

Description of OperationsVenoco, Inc. ("Venoco" or the "Company"), a Delaware corporation, is engaged in the
acquisition, exploration, exploitation and development of oil and natural gas properties with a focus on properties offshore and onshore in California and onshore in 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, 2008 includes certain definitions and a summary of
significant accounting policies and should be read in conjunction with this report. The results for interim periods are not necessarily indicative of annual results.

In
the course of preparing the condensed consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets,
liabilities, revenue
and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future
events and, accordingly, actual results could differ from amounts initially established. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas
reserves; (2) cash flow estimates used in ceiling tests of oil and natural gas properties; (3) depreciation, depletion and amortization; (4) asset retirement obligations;
(5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of commodity and
interest 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. At December 31, 2008 and March 31, 2009, the Company has recorded a valuation allowance against its net deferred tax assets since it cannot conclude that it is more
likely than not that the deferred tax assets will be fully realized on future tax returns. For the three months ended March 31, 2009, the tax expense recorded by the Company relates to federal
AMT and state income taxes.

Earnings Per ShareStatement of Financial Accounting Standards No. 128,Earnings Per
Share, requires presentation of "basic" and "diluted" earnings per share. 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 provides 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, as defined in SFAS 128. The Company's unvested restricted
stock awards contain certain nonforfeitable dividend rights. Accordingly, the Company adopted the FSP effective January 1, 2009.

Under
the two-class method, net income is reduced by dividends declared or paid in the current period. The remaining unallocated earnings are allocated between common stock
and participating

7

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

securities
(unvested restricted stock) in the same proportion that the securities share in dividends. Common stock and unvested restricted stock of the Company share equally in distributed earnings.
Basic EPS is calculated by dividing the earnings (distributed and undistributed) allocated to common stock by the weighted average shares outstanding. Diluted earnings per common share is calculated
by determining the most dilutive result between applying the two-class method or the treasury stock method. The Company's dilutive securities include non-qualified stock
options and unvested restricted stock.

The
treasury stock method is used to measure the dilutive impact of stock options and unvested restricted stock. The following table details the weighted average dilutive and
anti-dilutive securities for the periods presented (in thousands, except share and per share amounts):

Three Months Ended
March 31,2008

2009Dilutive





Anti-dilutive


4,627,806


4,585,028


Although
the Company recorded net income for the first quarter of 2009, due to the Company's low average stock price during the quarter compared to the average grant date fair value of
unvested restricted stock, the result of application of the treasury stock method to unvested restricted stock is anti-dilutive. Additionally, the exercise prices of all outstanding options are
greater than the average stock price for the first quarter of 2009 and also is anti-dilutive to the calculation.

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

Three Months Ended
March 31,2008

2009Net income (loss)

$
(25,456
)
$
25,205Allocation of net income to unvested restricted stock





(533
)Net income (loss) allocated to common stock

$
(25,456
)
$
24,672Basic weighted average common shares outstanding


50,227


50,702Add: dilutive effect of stock options and non-vested restricted stock





Diluted weighted average common shares outstanding


50,227


50,702Basic earnings per common share

$
(0.51
)
$
0.49Diluted earnings per common share

$
(0.51
)
$
0.49


Application
of the two-class method to the first quarter of 2008 would be anti-dilutive, therefore the two-class method has not been applied to the EPS calculation for the first quarter
of 2008.

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 reclassify commodity derivative (gains) losses

8

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

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.



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, effective January 1, 2009, has not had an impact on the Company's consolidated financial statements, other than additional
disclosures.

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. The Company adopted SFAS 141R, effective January 1,
2009, however the impact on the Company's consolidated financial statements will be dependent upon the nature, terms and size of the acquisitions the Company consummates.

In
February 2008, the FASB issued Staff Position FAS 157-2 (FSP No. 157-2), which delayed 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's non-recurring nonfinancial assets and nonfinancial liabilities include those measured at fair value in impairment testing for unproved properties, asset
retirement obligations initially measured at fair value, and those measured at fair value in a business combination. Effective January 1, 2009, the Company adopted the provisions of
SFAS 157 relative to its non-recurring nonfinancial assets and nonfinancial liabilities. The adoption did not have a material impact on the Company's balance sheet, results of
operations, or cash flows.

In
December 2008, the SEC published revised rules regarding oil and gas reserves reporting requirements. The objective of the rules are to provide readers of financial statements with
more meaningful and comprehensive understanding of oil and gas reserves. Key elements of the revised rules include a change in the pricing used to estimate reserves at period end, optional disclosure
of probable and possible reserves, allowance of the use of new technologies in the determination of reserves and additional disclosure requirements. The rules also revise the prices used for reserves
in determining depletion and the full cost ceiling test from a period end price to a 12-month average price. The revised rules are effective for annual reports for fiscal years ending on
or after December 31, 2009. Early adoption is not allowed. The Company is currently assessing the impact that the adoption of the

9

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

revised
rules will have on its operating results, financial position, cash flows, oil and natural gas reserves and disclosures.

2. ACQUISITIONS AND SALES OF PROPERTIES

Grayson County Acquisition.In September 2008, the Company acquired working interests in approximately 11,000 undeveloped acres
located in
Grayson County, Texas for approximately $5.9 million from an entity (the "Seller") affiliated with a former member of the Company's board of directors. Under the purchase and sale agreement,
the Company agreed to drill two horizontal test wells on the acreage by March 2010 to retain the acreage. 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.

Hastings Complex Sale.In February 2009, the Company closed the sale of its principal interests in the Hastings complex ("Hastings
Sale") to a
subsidiary of Denbury Resources Inc. ("Denbury") for approximately $201.0 million, subject to certain post-closing adjustments. The Company used the proceeds from the sale to
repay the full balance of the revolving credit facility of $187.1 million and related interest of $0.5 million. In addition, the Company paid $5.5 million toward the principal
balance on the second lien term loan. The Company did not recognize a gain for financial reporting purposes, but applied the proceeds from the Hastings Sale to reduce the capitalized cost of its oil
and natural gas properties.

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

Sacramento Basin Asset Acquisition.In February 2009, the Company entered into a purchase and sale agreement pursuant to which it
agreed to
buy properties in the Sacramento Basin from Aspen Exploration Corporation ("Aspen") and certain other parties for a total of approximately $25 million, subject to certain adjustments. The
closing of the transaction, which is subject to approval by Aspen's stockholders and other customary conditions, is currently scheduled to occur in the second quarter of 2009. In the first quarter of
2009, the Company paid a deposit of $2.4 million related to the acquisition.

10

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

3. LONG-TERM DEBT

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

December 31,
2008

March 31,
2009Revolving credit agreement due March 2011

$
135,052

$
5,620Second lien term loan due September 2011


500,000


494,4858.75% senior notes due December 2011


149,590


149,624Financed derivative premiums due through 2011


15,626


14,986Total long-term debt


800,268


664,715Less: current portion of long-term debt


(2,598
)

(4,521
)Long-term debt, net of current portion

$
797,670

$
660,194


Revolving credit facility.The Company has a $300.0 million revolving credit facility with a syndicate of banks ("revolving credit
facility"),
with a maturity date of March 30, 2011. 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 is unconditionally guaranteed by each of the Company's operating subsidiaries other than Ellwood Pipeline, Inc. The
collateral also secures the Company's obligations to hedging counterparties that are also lenders, or affiliates of lenders, under the 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 twice each year. In connection with the Hastings Sale, the borrowing base was re-determined in February 2009, resulting in a reduction of the borrowing base from
$200.0 million to $125.0 million. The Company expects a redetermination to be completed in May 2009. As of May 5, 2009, the Company had effective available borrowing
capacity of $112.6 million (net of the outstanding balance of $5.6 million, $0.9 million in outstanding letters of credit and $5.9 million attributable to Lehman Commercial
Papersee below) under the revolving credit facility.

The
borrowing base under the Company's revolving credit facility 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 $125.0 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 in September 2008. LCP is no longer funding its portion
of the Company's borrowing requests made under the facility. As of May 5, 2009, the Company had a balance of $5.6 million on the revolving credit facility. The Company's effective
borrowing base is $119.1 million, excluding $5.9 million related to LCP.

11

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

3. LONG-TERM DEBT (Continued)

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 still outstanding on September 20, 2011, principal on the term loan facility will be payable on that date.

The
Company may from time to time make optional prepayments of amounts borrowed under the facility (at par subsequent to May 7, 2009) if no amounts are outstanding under the
revolving credit facility. Amounts prepaid under the facility may not be reborrowed. As a result of the Hastings sale in February 2009, the Company was required to repay $5.5 million of
the outstanding principal balance on the second lien term loan.

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 March 31, 2009.

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.

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 may 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 Company's derivative contracts
are with multiple counterparties to minimize exposure to any individual counterparty. The Company generally

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

has
netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with that counterparty in the event of contract
termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. All of the counterparties to the Company's
derivative contracts are also lenders, or affiliates of lenders, under its revolving credit facility. Therefore, the Company is not required to post collateral when the Company is in a derivative
liability position. The Company's revolving credit facility and derivative contracts contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in
certain situations.

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

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. As of
March 31, 2009, the remaining unrealized derivative fair value loss of $1.7 million ($0.8 million after tax) for derivative contracts previously designated as cash flow hedges is
recorded in accumulated other comprehensive loss. The Company will amortize the remaining net unrealized derivative losses out of accumulated other comprehensive loss into earnings during the next
nine months. The Company amortized accumulated other comprehensive loss into oil and natural gas sales of $0.3 million and $0.6 million during the three months ended March 31,
2008 and 2009, respectively.

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

Three Months Ended
March 31,2008

2009Realized commodity derivative (gains) losses

$
18,263

$
(30,785
)Amortization of commodity derivative premiums


1,764


4,615Unrealized commodity derivative (gains) losses for changes in fair value


54,609


(22,389
)Commodity derivative (gains) losses

$
74,636

$
(48,559
)


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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 March 31, 2009, 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.

Minimum

MaximumBarrels/day

Avg. Prices

Barrels/day

Avg. PricesCrude oil derivatives at March 31, 2009 for production:April 1 - December 31, 2009


8,906

$
55.94


6,906

$
62.27January 1 - December 31, 2010


8,000

$
56.22


6,150

$
72.88January 1 - December 31, 2011


7,000

$
50.00


7,000

$
141.64


Natural Gas Agreements.As of March 31, 2009, the Company had entered into option, swap and collar agreements to receive average
minimum and
maximum NYMEX or PG&E Citygate prices as follows:

Minimum

MaximumMMBtu/Day

Avg. Prices

MMBtu/Day

Avg. PricesNatural gas derivatives at March 31, 2009 for production:April 1 - December 31, 2009


61,125

$
7.01


23,125

$
11.39January 1 - December 31, 2010


58,900

$
6.41


17,900

$
11.05January 1 - December 31, 2011


36,000

$
6.52


12,000

$
13.53


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. 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 $500.0 million of borrowings 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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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
March 31,2008

2009Realized interest rate derivative (gains) losses

$
417

$
3,940Unrealized interest rate derivative (gains) losses


13,554


(2,993
)Interest rate derivative (gains) losses, net

$
13,971

$
947


The
estimated fair values of derivatives included in the consolidated balance sheets at December 31, 2008 and March 31, 2009 are summarized below. The net fair value of the
Company's derivatives increased by $31.4 million from a net asset of $61.9 million at December 31, 2008 to a net asset of $93.3 million at March 31, 2009 due to
lower futures prices for natural gas, which are used in the calculation of the fair value of commodity derivatives, and a reduction of the remaining term of the contracts for interest derivatives. The
Company does not offset asset and liability positions with the same counterparties within the financial statements, rather, all contracts are presented at their gross estimated fair value. As of the
dates indicated, the Company's derivative assets and liabilities are presented below (in thousands). These balances represent the estimated fair value of the contracts. The

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

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

December 31,
2008

March 31,
2009Current AssetsCommodity derivatives:Oil derivative contracts

$
23,970

$
15,194Gas derivative contracts


33,277


57,91157,247


73,105Other AssetsCommodity derivatives:Oil derivative contracts


11,660


13,488Gas derivative contracts


23,654


35,80135,314


49,289Current LiabilitiesCommodity and interest derivatives:Oil derivative contracts


(1,672
)

(759
)Gas derivative contracts


(652
)

(3,148
)Interest rate derivative contracts


(18,960
)

(20,297
)(21,284
)

(24,204
)Commodity and interest derivatives:Gas derivative contracts


(180
)

Interest rate derivative contracts


(9,183
)

(4,853
)(9,363
)

(4,853
)Net derivative asset

$
61,914

$
93,337


5. FAIR VALUE MEASUREMENTS

Statement of Financial Accounting Standard No. 157 "Fair Value Measurements" (SFAS 157) defines fair value as the price that would be received in the sale of an asset or
paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would
use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or
generally unobservable. The Company classifies fair value balances based on the observability of those inputs. 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.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

5. FAIR VALUE MEASUREMENTS (Continued)

Level 2Pricing
inputs are other than quoted prices in active markets included in level 1, but are either directly or indirectly observable as of the reported
date. 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. 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 March 31, 2009 (in thousands).

Level 1

Level 2

Level 3

Fair Value
as of
March 31,
2009Assets (Liabilities):Commodity derivatives

$


$
122,394

$


$
122,394Commodity derivatives





(3,907
)




(3,907
)Interest rate swaps





(25,150
)




(25,150
)


6. ASSET RETIREMENT OBLIGATIONS

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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

6. ASSET RETIREMENT OBLIGATIONS (Continued)

The
following table summarizes the activities for the Company's asset retirement obligations for the three months ended March 31, 2008 and 2009 (in thousands):

Three Months Ended
March 31,2008

2009Asset retirement obligations at beginning of period

$
52,220

$
80,579Revisions of estimated liabilities


515


126Liabilities incurred


953


1,140Liabilities settled


(51
)

(106
)Disposition of properties





(2,993
)Accretion expense


993


1,357Asset retirement obligations at end of period


54,630


80,103Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)


(500
)

(1,075
)Long-term asset retirement obligations

$
54,130

$
79,028


7. CAPITAL STOCK

The Company has 58.8 million shares of common stock issued or reserved for issuance at March 31, 2009. At March 31, 2009, the Company has 52.4 million common
shares issued and outstanding, of which 1.7 million shares are restricted stock granted under the Company's 2005 stock incentive plan. At March 31, 2009, the Company had approximately
3.5 million options outstanding and 2.6 million shares available to be issued pursuant to awards under its stock incentive plans, including the 2008 Employee Stock Purchase Plan.

8. SHARE-BASED PAYMENTS

The Company has granted options to directors, certain employees and officers of the Company other than its CEO, under its 2000 and 2005 Stock Plans (the "Stock Plans"). As of
March 31, 2009, there are a total of 3,475,313 options outstanding with a weighted average exercise price of $9.09 ($6.00 to $20.00). The options vest over a four year period, with 20% vesting
on the grant date and 20% vesting on each subsequent anniversary of the grant date. The options typically have a maximum life of 10 years. The options will generally vest upon a change in
control of the Company. Unexercised options expire when an option holder elects to terminate employment or if the Company terminates the holder's employment for misconduct. If the Company terminates a
holder's employment other than for
misconduct, unvested options generally terminate and the holder has a limited period of time within which to exercise vested options, unless the award agreement provides otherwise.

In
November 2008, the Company's Board of Directors approved the 2008 Employee Stock Purchase Plan (the "ESPP") and the plan will be submitted to the Company's shareholders for
approval at the Company's 2009 annual shareholders' meeting. In connection with the approval of the ESPP, the Board authorized 1.5 million shares of common stock to be issued under the ESPP.
Participation in the ESPP is open to all employees, other than executive officers, who meet limited qualifications. Under the terms of the ESPP, employees are able to purchase Company stock at a 5%

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

8. SHARE-BASED PAYMENTS (Continued)

discount
as determined by the fair market value of the Company's stock on the last trading day of each purchase period. Individual employees are limited to $25,000 of common stock purchased in any
calendar year. The ESPP is non-compensatory, as defined by SFAS 123R. The ESPP became effective February 1, 2009.

As
of March 31, 2009, there were a total of 1,691,242 shares of restricted stock outstanding under the Company's 2005 stock incentive plan, including 632,737 shares granted to its
CEO. The restricted shares generally have a requisite service period of four years. The grant date fair value of restricted stock subject to service conditions only is determined by the closing stock
price, as published by the New York Stock Exchange, on the day prior to the date of grant. The vesting of 943,291 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 weighted-average fair value of the restricted shares subject to market conditions was derived using a Monte Carlo
technique and the fair value of awards granted was estimated to be $2.61 per share in 2009. As of March 31, 2009, none of the restricted shares subject to market conditions have vested. The
estimated grant date fair values of restricted share awards are recognized as expense over the requisite service periods.

The
following summarizes the Company's stock option activity for the three months ended March 31, 2009:

Options

Weighted
Average
Exercise
PriceOutstanding, start of period


3,504,263

$
9.16Granted





Exercised





Cancelled


(28,950
)

17.00Outstanding, end of period


3,475,313

$
9.09Exercisable, end of period


3,134,473

$
8.43


The
following summarizes the Company's unvested restricted stock award activity for the three months ended March 31, 2009:

Shares

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


851,545

$
12.57Granted


875,876


2.83Vested


(875
)

11.99Forfeited


(35,304
)

12.92Non-vested, end of period


1,691,242

$
7.56


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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

8. SHARE-BASED PAYMENTS (Continued)

In
accordance with SFAS 123R, the Company recognized total share-based compensation costs as follows (in thousands):

Three Months Ended
March 31,2008

2009General and administrative expense

$
1,240

$
1,120Oil and natural gas production expense


100


130Total share-based compensation costs


1,340


1,250Less: share-based compensation costs capitalized


(553
)

(700
)Share-based compensation expensed

$
787

$
550


As
of March 31, 2009, there was $1.5 million of total unrecognized compensation cost related to stock options which is expected to be amortized over a weighted-average
period of 1.8 years and $8.3 million of total unrecognized compensation cost related to restricted stock which is expected to be amortized over a weighted-average period of
3.0 years.

9. 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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

9. LITIGATION (Continued)

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 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.

10. GUARANTOR FINANCIAL INFORMATION

All subsidiaries of the Company other than Ellwood Pipeline Inc. ("Guarantors") have fully and unconditionally guaranteed, on a joint and several basis, the Company's obligations
under the senior notes. Ellwood Pipeline, Inc. is not a Guarantor (the "Non-Guarantor Subsidiary"). The condensed consolidating financial information for prior periods has been
revised to reflect the guarantor and non-guarantor status of the Company's subsidiaries as of March 31, 2009. All Guarantors are 100% owned by the Company. Presented below are the
Company's condensed consolidating balance sheets, statements of operations and statements of cash flows as required by Rule 3-10 of Regulation S-X of the
Securities Exchange Act of 1934.

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Table of Contents

CONDENSED CONSOLIDATING BALANCE SHEETS        AT DECEMBER 31, 2008        (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedASSETSCURRENT ASSETS:Cash and cash equivalents

$
190

$
1

$


$


$
191Accounts receivable


33,654


7,652








41,306Inventories


5,544


6,817








12,361Prepaid expenses and other current assets


4,314











4,314Income taxes receivable


546











546Commodity derivatives


57,247











57,247TOTAL CURRENT ASSETS


101,495


14,470








115,965PROPERTY, PLANT & EQUIPMENT, NET


580,317


121,353


1,064





702,734COMMODITY DERIVATIVES


35,314











35,314INVESTMENTS IN AFFILIATES


498,670








(498,670
)

OTHER


9,546


695








10,241TOTAL ASSETS

$
1,225,342

$
136,518

$
1,064

$
(498,670
)
$
864,254LIABILITIES AND STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities

$
67,832

$
7,568

$


$


$
75,400Undistributed revenue payable


8,277











8,277Interest payable


5,325











5,325Current maturities of long-term debt


2,598











2,598Commodity and interest derivatives


21,284











21,284TOTAL CURRENT LIABILITIES:


105,316


7,568








112,884LONG-TERM DEBT


797,670











797,670COMMODITY AND INTEREST DERIVATIVES


9,363











9,363ASSET RETIREMENT OBLIGATIONS


68,678


10,107


719





79,504INTERCOMPANY PAYABLES (RECEIVABLES)


379,482


(336,243
)

(43,239
)




TOTAL LIABILITIES


1,360,509


(318,568
)

(42,520
)




999,421TOTAL STOCKHOLDERS' EQUITY


(135,167
)

455,086


43,584


(498,670
)

(135,167
)TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
1,225,342

$
136,518

$
1,064

$
(498,670
)
$
864,254


22

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Table of Contents

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

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedASSETSCURRENT ASSETS:Cash and cash equivalents

$
15,019

$
1

$


$


$
15,020Accounts receivable


28,503


2,947


91





31,541Inventories


4,045


166








4,211Prepaid expenses and other current assets


3,856











3,856Commodity derivatives


73,105











73,105TOTAL CURRENT ASSETS


124,528


3,114


91





127,733PROPERTY, PLANT & EQUIPMENT, NET


616,252


(74,073
)

1,041





543,220COMMODITY DERIVATIVES


49,289











49,289INVESTMENTS IN AFFILIATES


501,291








(501,291
)

OTHER


9,199


673








9,872TOTAL ASSETS

$
1,300,559

$
(70,286
)
$
1,132

$
(501,291
)
$
730,114LIABILITIES AND STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities

$
34,781

$
5,826

$


$


$
40,607Undistributed revenue payable


9,017











9,017Interest payable


7,384











7,384Income taxes payable


8,304











8,304Current maturities of long-term debt


4,521











4,521Commodity and interest derivatives


24,204











24,204TOTAL CURRENT LIABILITIES:


88,211


5,826








94,037LONG-TERM DEBT


660,194











660,194COMMODITY AND INTEREST DERIVATIVES


4,853











4,853ASSET RETIREMENT OBLIGATIONS


71,022


7,273


733





79,028INTERCOMPANY PAYABLES (RECEIVABLES)


584,277


(539,392
)

(44,885
)




TOTAL LIABILITIES


1,408,557


(526,293
)

(44,152
)




838,112TOTAL STOCKHOLDERS' EQUITY


(107,998
)

456,007


45,284


(501,291
)

(107,998
)TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
1,300,559

$
(70,286
)
$
1,132

$
(501,291
)
$
730,114


23

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Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS        THREE MONTHS ENDED MARCH 31, 2008 (Unaudited)        (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
102,003

$
34,662

$


$


$
136,665Other


683


9


1,211


(1,118
)

785Total revenues


102,686


34,671


1,211


(1,118
)

137,450EXPENSES:Oil and natural gas production


20,911


10,749


349





32,009Transportation expense


2,341








(1,044
)

1,297Depletion, depreciation and amortization


25,249


5,974


23





31,246Accretion of abandonment liability


784


193


16





993General and administrative, net of amounts capitalized


8,468


598


74


(74
)

9,066Total Expenses


57,753


17,514


462


(1,118
)

74,611Income (loss) from operations


44,933


17,157


749





62,839FINANCING COSTS AND OTHER:Interest expense, net


15,347


(8
)

(750
)




14,589Amortization of deferred loan costs


999











999Interest rate derivative losses (gains), net


13,971











13,971Commodity derivative losses (gains), net


74,636











74,636Total financing costs and other


104,953


(8
)

(750
)




104,195Equity in subsidiary income


11,488








(11,488
)

Income (loss) before income taxes


(48,532
)

17,165


1,499


(11,488
)

(41,356
)Income tax provision (benefit)


(23,076
)

6,600


576





(15,900
)Net income (loss)

$
(25,456
)
$
10,565

$
923

$
(11,488
)
$
(25,456
)


24

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Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS        THREE MONTHS ENDED MARCH 31, 2009 (Unaudited)        (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
48,221

$
9,210

$


$


$
57,431Other


763


22


1,411


(1,311
)

885Total revenues


48,984


9,232


1,411


(1,311
)

58,316EXPENSES:Oil and natural gas production


21,426


4,827


473





26,726Transportation expense


2,262


15





(1,231
)

1,046Depletion, depreciation and amortization


19,913


2,746


24





22,683Accretion of asset retirement obligations


1,185


159


13





1,357General and administrative, net of amounts capitalized


7,431


567


80


(80
)

7,998Total expenses


52,217


8,314


590


(1,311
)

59,810Income (loss) from operations


(3,233
)

918


821





(1,494
)FINANCING COSTS AND OTHER:Interest expense, net


12,060


(3
)

(879
)




11,178Amortization of deferred loan costs


735











735Interest rate derivative losses (gains), net


947











947Commodity derivative losses (gains), net


(48,559
)










(48,559
)Total financing costs and other


(34,817
)

(3
)

(879
)




(35,699
)Equity in subsidiary income


1,625








(1,625
)

Income (loss) before income taxes


33,209


921


1,700


(1,625
)

34,205Income tax provision (benefit)


8,004


350


646





9,000Net income (loss)

$
25,205

$
571

$
1,054

$
(1,625
)
$
25,205


25

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Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS        THREE MONTHS ENDED MARCH 31, 2008 (Unaudited)        (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

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

$
20,377

$
18,607

$
971

$


$
39,955CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for oil and natural gas properties


(67,075
)

(13,417
)

(3
)




(80,495
)Acquisitions of oil and natural gas properties


(3,300
)

(2,028
)







(5,328
)Expenditures for property and equipment and other


(968
)

(53
)







(1,021
)Net cash provided by (used in) investing activities


(71,343
)

(15,498
)

(3
)




(86,844
)CASH FLOWS FROM FINANCING ACTIVITIES:Net proceeds from (repayments of) intercompany borrowings


5,050


(4,082
)

(968
)




Proceeds from long-term debt


60,000











60,000Principal payments on long-term debt


(10,893
)










(10,893
)Payments for deferred loan costs


(68
)










(68
)Proceeds from derivative premium financing


2,488











2,488Stock issuance costs


(5
)










(5
)Proceeds from exercise of stock options


29











29Net cash provided by (used in) financing activities


56,601


(4,082
)

(968
)




51,551Net increase (decrease) in cash and cash equivalents


5,635


(973
)







4,662Cash and cash equivalents, beginning of period


8,762


973








9,735Cash and cash equivalents, end of period

$
14,397

$


$


$


$
14,397


26

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Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS        THREE MONTHS ENDED MARCH 31, 2009 (Unaudited)        (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

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

$
7,547

$
13,462

$
1,646

$


$
22,655CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for oil and natural gas properties


(66,932
)

(1,933
)







(68,865
)Acquisitions of oil and natural gas properties


(2,664
)










(2,664
)Expenditures for property and equipment and other


(1,211
)

534








(677
)Proceeds from sale of oil and natural gas properties





200,060








200,060Net cash provided by (used in) investing activities


(70,807
)

198,661








127,854CASH FLOWS FROM FINANCING ACTIVITIES:











Net proceeds from (repayments of) intercompany borrowings


213,769


(212,123
)

(1,646
)




Proceeds from long-term debt


57,626











57,626Principal payments on long-term debt


(193,357
)










(193,357
)Payments for deferred loan costs


(40
)










(40
)Proceeds from Employee Stock Purchase Plan


76











76Proceeds from disgorgement of stock sale profits


15











15Net cash provided by (used in) financing activities


78,089


(212,123
)

(1,646
)




(135,680
)Net increase (decrease) in cash and cash equivalents


14,829











14,829Cash and cash equivalents, beginning of period


190


1








191Cash and cash equivalents, end of period

$
15,019

$
1

$


$


$
15,020


27

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Table of Contents

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

The following discussion and analysis should be read in conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" contained in our Annual Report on Form 10-K for the year ended December 31, 2008 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 21,728 BOE/d in the first quarter of 2009, compared to 21,026 BOE/d in the first quarter of 2008 and 22,674 BOE/d in the fourth quarter of 2008. Excluding
production from the Hastings complex, which we sold on February 2, 2009 (see "Acquisitions and Divestitures"), our average net production was 20,818 BOE/d in the first
quarter of 2009, compared to 18,380 BOE/d in the first quarter of 2008 and 20,103 BOE/d in the fourth quarter of 2008.

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

Capital Expenditures

We have developed an active capital expenditure program to take advantage of our extensive inventory of drilling prospects and other
projects. Our development, exploitation and exploration capital expenditure budget for 2009 is $150.0 million, of which approximately $53.2 million (excluding changes in accrued capital
expenditures) was expended in the first three months of 2009. We expect to spend approximately 54% of the budgeted amount on projects in the Sacramento Basin, 28% in Southern California, 6% in Texas
and 12% for exploration projects in a variety of areas. We have entered into hedging arrangements to secure floors on 100% of our forecast 2009 production. The price floors are intended to ensure a
minimum revenue stream to support an active capital expenditure program and satisfy our other obligations. The aggregate levels of capital expenditures for the remainder of 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 2009 capital spending program:

Southern CaliforniaExploitation and Development

Our primary focus in Southern California in 2009 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. During the first three months of 2009, we completed two wells that were spud
during the fourth quarter of 2008 and performed three workovers and recompletions. We plan to drill two additional wells in the West Montalvo field later in 2009.

28

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Table of Contents

In
the Sockeye field, we continue to implement and optimize our waterflood program from platform Gail. During the first three months of the year, we spud one well at Sockeye. We are
currently in the process of completing the well, which, if successful, will produce from the Monterey formation and inject into the Upper Topanga formation to expand the waterflood.

In
the South Ellwood field, the permitting process continues for our full-field development project. We anticipate receiving a final environmental impact report relating to
the project in 2009 and for the project approval hearings to begin thereafter. Key components of the project include an extension of the current lease boundary (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. We may pursue permits necessary for the pipeline separately from those required for
the overall project. Development of the lease extension area can be accomplished from the field's existing platform. We have been pursuing the pipeline permitting process and acquiring
rights-of-way. Our 2009 capital expenditure budget includes a small amount for continued work towards pipeline permitting and acquisition of
rights-of-way.

Sacramento BasinExploitation and Development

In the Sacramento Basin, we continue to pursue our infill drilling program in the greater Grimes and Willows fields. Currently, we have
three drilling rigs and seven workover/completion rigs working in the basin and expect to drill over 70 new wells and perform more than 100 workovers and recompletions there in 2009. During the first
three months of 2009, we
spudded 24 wells, completed 18 (including wells spud in 2008), and performed 57 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 over 70 wells since the start of the program. We are encouraged by the results and continue to analyze the fracs in order to optimize future fracture simulations in
the basin. We plan to fracture approximately 12 wells in the basin during 2009, but did not fracture any wells during the first quarter.

TexasExploitation and Development

In Texas, our focus has shifted from the recently sold Hastings complex to the development of our other Texas properties. Our 2009
capital expenditure budget includes capital for up to three new development wells and approximately seven workovers and recompletions. During the first three months of 2009, we performed one workover
in Texas.

Following
the sale of the Hastings complex, our largest operated field in Texas is now the Manvel field. We intend to utilize the knowledge and experience we gained operating the
Hastings complex to redevelop this field. This program will consist mainly of returning idle wells to production, increasing the lift capacity of existing wells, working over and recompleting existing
wells in different producing sands, upgrading surface facility fluid handling capacity and increasing water injection capabilities. In addition, we are currently in the process of unitizing the Manvel
field and believe it is a solid candidate for a CO2 flood operation.

Exploration Activities

During the first three months of the year we spudded two exploration wells in Washington. One of those wells has been scheduled to be
plugged and abandoned and the other is currently being evaluated.

29

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Table of Contents

Acquisitions and Divestitures

Hastings Sale.In February 2009, we completed the sale of our principal interests in the Hastings complex to Denbury for approximately
$201.0 million. As a result of the sale, we repaid all amounts outstanding under our revolving credit facility and paid $5.5 million of the outstanding principal balance on our second
lien term loan facility.

For
illustrative purposes, we have presented below, historical production volumes and the results of operations attributable to the Hastings complex for the three month periods ended
March 31, 2008 and 2009 (which includes only January for the 2009 period).

Three Months Ended
March 31,2008

2009Production Volume:Oil (MBbls)


237


81Natural gas (MMcf)


21


4Statement of Operations (in thousands):Oil sales

$
23,555

$
3,275Gas sales


174


19Lease operating expenses


7,620


1,636Production and property taxes


1,469


332Lease Operating Expenses per BOE

$
31.70

$
19.06


Sacramento Basin Asset Acquisition.In February 2009, we entered into a purchase and sale agreement pursuant to which we agreed to buy
properties in
the Sacramento Basin from Aspen Exploration Corporation ("Aspen") and certain other parties for a total of approximately $25 million, subject to certain adjustments. The closing of the
transaction, which is subject to approval by Aspen's shareholders and other customary conditions, is currently scheduled to occur in the second quarter of 2009. In the first quarter of 2009, we paid a
deposit of $2.4 million related to the acquisition.

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

Oil and Natural Gas Prices.Historically, prices received for our oil and natural gas production have been volatile and unpredictable,
and that
volatility is expected to continue. Changes in the market prices for oil and natural gas directly impact many aspects of our business, including our financial condition, revenues, results of
operations, liquidity, rate of growth, the carrying value of our oil and natural gas properties and borrowing capacity under our revolving credit facility, all of which depend primarily or in part
upon those prices. For example, as a result of lower commodity prices at December 31, 2008, we were required to record a full cost ceiling impairment of our oil and gas properties in the fourth
quarter. Additionally, if commodity prices continue to deteriorate throughout 2009, we may be required to record another ceiling impairment of our oil and natural gas properties. Continued low prices
in early 2009 contributed significantly to a February 2009 reduction in the borrowing base under our revolving credit facility. In addition, as a result of declines in commodity prices, as well as the
deterioration in the overall economy, we significantly reduced our capital expenditures planned for 2009 as compared to our actual capital expenditures incurred in 2008. In order to reduce the
variability of the prices we receive for our production and provide a minimum revenue stream, we employ a hedging strategy. As of March 31, 2009, we had hedge contract floors covering
approximately 100% of our 2009 production guidance, in excess of 90% of our anticipated

30

---



Table of Contents

2010
production and in excess of 60% of our anticipated 2011 production. All of our derivatives counterparties are members, or affiliates of members, of our revolving credit facility syndicate. See
"Quantitative and Qualitative Disclosures About Market RiskCommodity Derivative Transactions" for further details concerning our hedging activities.

Expected Production.We expect that the execution of our capital expenditure program in 2009 will result in average daily production
volumes in 2009
that are consistent with 2008 volumes, pro forma for the Hastings sale, or approximately 19,000 BOE/d. We expect our Southern California properties, which produced 3.0 MMBOE during 2008 (of which 94%
was oil), to exhibit modest production growth as compared to 2008. In particular, we expect the drilling and workover/recompletion programs at the West Montalvo field to result in production increases
there in 2009. In the Sacramento Basin, we intend to continue our multi-year drilling program and plan to drill more than 70 new wells and perform over 100 workovers and recompletions. As
a result of reducing the number of rigs active in the basin to three, we expect average daily production in the basin to decline over the course of 2009 but expect full year average net production to
be relatively flat compared to average 2008 net production from the basin. At the Manvel field, which we acquired in April 2007, we are continuing a redevelopment program by upgrading our fluid
handling and injection capacity and plan to drill two new wells and perform approximately five workovers and recompletions. 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, changes in our capital expenditure budget and other factors, including those referenced in "Risk Factors."

31

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Table of Contents

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 months ended March 31, 2008 and 2009.

Three Months Ended
March 31,2008

2009Production Volume:Oil (MBbls)(1)


984


934Natural gas (MMcf)


5,576


6,129MBOE


1,913


1,956Daily Average Production Volume:Oil (Bbls/d)


10,813


10,378Natural gas (Mcf/d)


61,275


68,100BOE/d


21,026


21,728Oil Price per Bbl Produced (in dollars):Realized price

$
90.84

$
34.40Realized commodity derivative gain (loss) and amortization of commodity derivative premiums


(18.49
)

9.58Net realized price

$
72.35

$
43.98Natural Gas Price per Mcf (in dollars):Realized price

$
7.88

$
4.41Realized commodity derivative loss and amortization of commodity derivative premiums


(0.01
)

1.87Net realized price

$
7.87

$
6.28Average Sales Price per BOE(2)

$
59.21

$
37.62Expense per BOE:Lease operating expenses(3)

$
14.68

$
11.78Production and property taxes(3)


2.05


1.88Transportation expenses


0.68


0.53Depreciation, depletion and amortization


16.33


11.60General and administrative expense(4)


4.74


4.09Interest expense


7.63


5.71






32

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Table of Contents



Comparison of Quarter Ended March 31, 2009 to Quarter Ended March 31, 2008

Oil and Natural Gas Sales.Oil and natural gas sales decreased $79.3 million (58%) to $57.4 million for the quarter ended
March 31, 2009 from $136.7 million for the same period in 2008. The decrease was primarily due to a decrease in average sales prices partially offset by an increase in production as
further described below.

Oil
sales decreased by $62.3 million (67%) in the first quarter of 2009 to $30.4 million compared to $92.7 million in the first quarter of 2008. Oil production
decreased by 5%, with production of 934 MBbl in the first quarter of 2009 compared to 984 MBbl in the first quarter of 2008. The production decrease was primarily due to the sale of the
Hastings complex in early February 2009. Excluding Hastings, production increased 106 MBbl (14%) from 747 MBbl in the first quarter of 2008 to 853 MBbl in the first quarter of
2009. The increase is primarily due to increased production at the West Montalvo and Sockeye fields as a result of drilling and recompletion activities in the latter half of 2008 and the first quarter
of 2009. Our average realized price for oil decreased $56.44 (62%) to $34.40 per Bbl for the period.

Natural
gas sales decreased $16.9 million (39%) in the first quarter of 2009 to $27.0 million compared to $43.9 million in the first quarter of 2008. Natural gas
production increased 10%, with production of 6,129 MMcf in the first quarter of 2009 compared to 5,576 MMcf in the first quarter of 2008. The increase was due primarily to drilling, recompletion and
hydraulic fracturing activities in the Sacramento Basin. Our average realized price for natural gas decreased $3.47 (44%) to $4.41 per Mcf for the period.

Other Revenues.Other revenue remained relatively constant at $0.9 million in the first quarter of 2009 compared to
$0.8 million in the
first quarter of 2008.

Production Expenses.Production expenses, which consist of lease operating expenses ("LOE") and production/property taxes, decreased
$5.3 million (17%) to $26.7 million in the first quarter of 2009 from $32.0 million in the first quarter of 2008. The decrease was primarily due to the sale of Hastings in early
February 2009 which was historically a relatively high cost field. On a per unit basis, LOE decreased to $11.78 per BOE in the first quarter of 2009 from $14.68 per BOE in the same period in 2008.
Excluding Hastings, LOE per BOE decreased $0.81 from $12.24 per BOE in the first quarter of 2008 to $11.43 per BOE in the first quarter of 2009. The decrease is partially due to the increased
proportion of Sacramento Basin natural gas production during the first quarter of 2009, which has lower operating costs than oil production. Additionally, we realized cost reductions related to
maintenance and environmental costs in Southern California, as well as price/cost reductions from external contractors and suppliers.

Transportation Expenses.Transportation expenses decreased $0.3 million (19%) to $1.0 million in the first quarter of 2009
from
$1.3 million in the first quarter of 2008. On a per BOE basis, transportation expenses decreased $0.15 per BOE, from $0.68 per BOE in the first quarter of 2008 to $0.53 per BOE in the first
quarter of 2009.

Depletion, Depreciation and Amortization (DD&A).DD&A expense decreased $8.5 million (27%) to $22.7 million in the
first quarter of
2009 from $31.2 million in the first quarter of 2008. DD&A expense decreased $4.73 per BOE, from $16.33 per BOE in the first quarter of 2008 to $11.60 per BOE in the first quarter of 2009. The
decrease is due to a reduced amortizable base as a result of the full cost ceiling write down recorded at December 31, 2008, and the application of proceeds from the sale of the Hasting complex
in February 2009 to reduce the full cost pool.

Accretion of Abandonment Liability.Accretion expense increased $0.4 million (37%) to $1.4 million in the first quarter of
2009 from
$1.0 million in the first quarter of 2008. The increase was

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due
to revisions to estimated liabilities recorded in the fourth quarter of 2008 and accretion from new wells drilled and completed in 2008 and the first three months of 2009.

General and Administrative (G&A).G&A expense decreased $1.1 million (12%) to $8.0 million in the first quarter of
2009 from
$9.1 million in the first quarter of 2008. The decrease primarily resulted from an increase in the G&A costs that were capitalized for payroll and related overhead for activities that are
directly involved in our development, exploitation, exploration and acquisition efforts. This decrease was partially offset by increases in our professional staff and related infrastructure.
Non-cash SFAS 123R compensation expense charged to G&A decreased $0.3 million (39%) from $0.7 million in 2008 to $0.4 million in 2009, primarily as a result of
certain awards which fully vested during the quarter. Excluding the effect of the non-cash SFAS 123R compensation expense charges, G&A expense decreased $0.51 from $4.38 per BOE in
the first quarter of 2008 to $3.87 per BOE in the first quarter of 2009.

Interest Expense, Net.Interest expense, net of interest income, decreased $3.4 million (23%) from $14.6 million in the first
quarter
of 2008 to $11.2 million in the first quarter of 2009. The decrease was primarily the result of a reduction in our average debt outstanding due to the repayment of the balance on the revolving
credit facility in the first quarter of 2009 and lower interest rates realized during the first quarter of 2009.

Amortization of Deferred Loan Costs.Amortization of deferred loan costs decreased $0.3 million, from $1.0 million in the
first quarter
of 2008 to $0.7 million in the first quarter of 2009. 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 (Gains) Losses, Net.Changes in the fair value of our interest rate swap derivative instruments resulted in
unrealized gains
of $3.0 million in the first quarter of 2009 and unrealized losses of $13.6 million in the 2008 period. Unrealized interest rate (gains) losses are the result of the change in the fair
value of our interest rate derivatives. The unrealized gain for the three months ended March 31, 2009 is primarily due to the reduction of the remaining term of the contracts since future
interest rates remained relatively constant between December 31, 2008 and March 31, 2009. Realized interest rate swap losses were $3.9 million in the first quarter of 2009
compared to realized losses of $0.4 million in the first quarter of 2008.

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

Three Months Ended
March 31,2008

2009Realized commodity derivative (gains) losses

$
18,263

$
(30,785
)Amortization of derivative premiums


1,764


4,615Unrealized commodity derivative (gains) losses for changes in fair value


54,609


(22,389
)Commodity derivative (gains) losses

$
74,636

$
(48,559
)


Realized
commodity derivative gains or losses represent the difference between the strike prices in the contracts settled during the period and the ultimate settlement prices. The
realized commodity derivative gains in the first quarter of 2009 reflect the settlement of contracts at prices below the relevant strike prices, while the realized derivative loss in the first quarter
of 2008 reflects the settlement of contracts at prices above the relevant strike prices. In addition, in the first quarter of

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2009,
we unwound certain oil collars and purchased oil swaps with the proceeds. We also unwound certain 2009 gas puts to bring our hedge position in line with our production guidance. As a result of
these transactions, we realized non-recurring gains of $10.4 million which are reflected in realized commodity derivative (gains) losses. Unrealized commodity derivative (gains)
losses represent the change in the fair value of our open derivative contracts from period to period. The change in unrealized commodity derivative (gains) losses reflects 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).We provided a valuation allowance against our net deferred tax assets at December 31, 2008 and
March 31,
2009 since we could not conclude that it is more likely than not that the net deferred tax assets will be recognized. The current tax expense for the first quarter of 2009 relates to federal AMT and
state income taxes. The net loss for the first quarter of 2008 resulted in an income tax benefit of $15.9 million.

Net Income (Loss).Net income for the first quarter of 2009 was $25.2 million compared to net loss of $25.5 million for the
same period
in 2008. The change between periods is the result of the items discussed above.

Liquidity and Capital Resources

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

Cash Flows

Three Months Ended
March 31,2008

2009(in thousands)Cash provided by operating activities

$
39,955

$
22,655Cash (used in) provided by investing activities


(86,844
)

127,854Cash (used in) provided by financing activities


51,551


(135,680
)


Net
cash provided by operating activities was $22.7 million in the first three months of 2009 compared with $40.0 million in the first three months of 2008. Cash flows from
operating activities in the first three months of 2009 were unfavorably impacted by decreases in commodity prices and net premiums paid on derivative contracts.

Net
cash provided by investing activities was $127.9 million in the first three months of 2009 compared with $86.8 million used in the first three months of 2008. The
primary investing activities in the first three months of 2009 were receipt of $200.1 million in cash proceeds from the sale of the Hastings complex offset by $71.5 million in capital
expenditures on oil and natural gas properties related to our 2009 capital expenditure program. The primary investing activities in the first three months of 2008 include $85.8 million in
capital expenditures on oil and gas properties.

Net
cash used in financing activities was $135.7 million in the first three months of 2009 compared to $51.6 million provided by financing activities in the first three
months of 2008. The primary financing activities in the first three months of 2009 were $129.4 million in net payments made on our revolving credit facility paid with proceeds from the Hastings
complex sale. Additionally, we paid $5.5 million of the principal balance on the second lien term loan with the Hastings sale proceeds. Financing activities in the first three months of 2008
included $49.1 million in net borrowings under our revolving credit facility to fund capital expenditures and working capital needs.

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Capital Resources and Requirements

We plan to make substantial capital expenditures in the future for the acquisition, exploration, exploitation and development of oil
and natural gas properties. We expect that our exploration, exploitation and development capital expenditures will be approximately $150.0 million in 2009. We intend to finance these capital
expenditures and the Aspen acquisition (see "Acquisitions and DivestituresSacramento Basin Asset Acquisition") through a combination of cash flow from operations, cash on
hand and borrowings under our revolving credit facility. However, we expect to be able to maintain substantial borrowing availability on our revolving credit facility throughout the year.
Uncertainties relating to our capital resources and requirements in 2009 include the possibility that one or more of the counterparties to our hedging arrangements fails to perform under the contracts
and the possibility that we will pursue one or more significant acquisitions that would require additional debt or equity financing.

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. The minimum ratio of current assets to current liabilities (as those terms are defined in the agreement) is one to one; the maximum ratio of debt to
EBITDA (as defined in the agreement) is four to one. The revolving credit facility has a total capacity of $300.0 million, but is limited by a borrowing base currently established at
$125.0 million. The borrowing base is subject to redetermination twice each year, and may be redetermined at other times at our request or at the request of the lenders. We expect a
redetermination to be completed in May 2009. 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.

In
anticipation of the Hastings sale, in January 2009 we requested a redetermination of the borrowing base under the revolving credit facility. Consequently, effective with the sale, the
borrowing base was reduced from $200.0 million to $125.0 million. Lending commitments under the facility have been allocated at various percentages to a syndicate of twelve 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 borrowing base
has been allocated to Lehman Commercial Paper ("LCP"), a wholly-owned subsidiary of Lehman Brothers Holding, Inc., which filed for bankruptcy protection in September 2008. LCP is no longer
funding its portion of our borrowing requests made under the facility. Accordingly, our effective borrowing base is $119.1 million, excluding $5.9 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. As a result of the Hastings sale in February 2009, we repaid
the outstanding balance of the facility in full. Subsequently, we borrowed approximately $5.6 million solely to maintain a balance of variable rate debt equivalent to the notional amount of our
interest rate swap. See "Quantitative and Qualitative Disclosures About Market Risk." While we do not expect to be in violation of any of our debt covenants during 2009, we believe

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that
it will be important to monitor the requirement that we maintain a specified ratio of debt to EBITDA (as defined in the agreement governing the revolving credit facility), in particular if
commodity prices do not increase and we pursue our current capital expenditure plan. We do not currently expect to borrow any additional amounts under the facility until late in the second quarter or
early in the third quarter of 2009. If we believe at that time that borrowing under the facility will give rise to a significant possibility of a covenant default, we may take a variety of actions,
including but not limited to reducing our capital expenditure budget.

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

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 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 at a redemption price initially equal to 104.375% of the principal amount and declining to 100% of the principal amount by December 15, 2010.
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.

Principal
on our second lien term loan facility is payable on May 8, 2014. However, if the senior notes are not refinanced in full prior to September 20, 2011, principal on
the second lien term loan facility will be payable on that date. In order to preserve the later maturity date for the second lien term loan, we expect to pursue a refinancing of the senior notes. We
are currently considering different refinancing options and will likely seek to exercise one of those refinancing options during 2009 if we believe market conditions are appropriate. If currently
adverse conditions in the credit markets persist or worsen, it may be more difficult, or impossible, to refinance the senior notes.

Because
we must dedicate a substantial portion of our cash flow from operations to the payment of amounts due under our debt agreements, that portion of our cash flow is not available
for other purposes. Our ability to make scheduled interest payments on our indebtedness and pursue our capital expenditure plan will depend to a significant extent on our financial and operating
performance, which

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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 March 31, 2009, 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 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 March 31, 2009, 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 difference
between the agreement price and the actual NYMEX crude oil price.

Minimum

MaximumBarrels/day

Avg. Prices

Barrels/day

Avg. PricesCrude oil derivatives at March 31, 2009 for production:April 1 - December 31, 2009


8,906

$
55.94


6,906

$
62.27January 1 - December 31, 2010


8,000

$
56.22


6,150

$
72.88January 1 - December 31, 2011


7,000

$
50.00


7,000

$
141.64


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Natural Gas.As of March 31, 2009, we had entered into derivative agreements to receive average minimum and maximum NYMEX or
PG&E Citygate
prices as follows:

Minimum

MaximumMMBtu/Day

Avg. Prices

MMBtu/Day

Avg. PricesNatural gas derivatives at March 31, 2009 for production:April 1 - December 31, 2009


61,125

$
7.01


23,125

$
11.39January 1 - December 31, 2010


58,900

$
6.41


17,900

$
11.05January 1 - December 31, 2011


36,000

$
6.52


12,000

$
13.53


Portfolio of Derivative Transactions

Our portfolio of commodity derivative transactions as of March 31, 2009 is summarized below:

Oil

Type of Contract

Counterparty

Basis

Quantity
(Bbl/d)

Strike Price
($/Bbl)

TermSwap

Bank of Montreal

NYMEX


2,170

$53.28


Apr 1 - Jun 30, 09Collar

Bank of Montreal

NYMEX


50

$60.00/$82.75


Apr 1 - Jun 30, 09Swap

Bank of Montreal

NYMEX


1,000

$59.75


Jul 1 - Dec 31, 09Swap

Fortis Bank

NYMEX


2,000

$67.22


Apr 1 - Dec 31, 09Swap

Bank of Montreal

NYMEX


3,000

$58.14


Apr 1 - Dec 31, 09Collar

Bank of Montreal

NYMEX


750

$60.00/$82.75


Jul 1 - Dec 31, 09Put

Bank of Montreal

NYMEX


2,000

$40.00


Apr 1 - Dec 31, 09Collar

Bank of Oklahoma

NYMEX


3,500

$60.00/$73.00


Jan 1 - Dec 31, 10Swap

Fortis Bank

NYMEX


1,000

$66.75


Jan 1 - Dec 31, 10Collar

Fortis Bank

NYMEX


1,000

$60.00/$72.80


Jan 1 - Dec 31, 10Collar

Bank of Montreal

NYMEX


650

$60.00/$81.75


Jan 1 - Dec 31, 10Put

Scotia Bank

NYMEX


1,850

$40.00


Jan 1 - Dec 31, 10Collar

Key Bank

NYMEX


2,000

$50.00/$141.00


Jan 1 - Dec 31, 11Collar

Key Bank

NYMEX


2,000

$50.00/$144.75


Jan 1 - Dec 31, 11Collar

Credit Suisse

NYMEX


3,000

$50.00/$140.00


Jan 1 - Dec 31, 11


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Natural Gas

Type of Contract

Counterparty

Basis

Quantity
(MMBtu/d)

Strike Price
($/MMBtu)

TermCollar

Credit Suisse

NYMEX


1,250

$
7.75/$13.05


Apr 1 - Jun 30, 09Swap

Credit Suisse

NYMEX


1,250

$
8.72


Apr 1 - Jun 30, 09Basis Swap

Bank of Montreal

PG&E Citygate


6,000

$
0.10


Apr 1 - Dec 31, 09Basis Swap

Bank of Montreal

PG&E Citygate


7,500

$
0.11


Apr 1 - Dec 31, 09Collar

Bank of Montreal

NYMEX


1,125

$
8.00/$12.00


Apr 1 - Dec 31, 09Collar

Bank of Montreal

NYMEX


4,000

$
7.30/$9.85


Apr 1 - Dec 31, 09Collar

Bank of Montreal

NYMEX


7,000

$
7.50/$12.75


Apr 1 - Dec 31, 09Collar

Credit Suisse

NYMEX


8,500

$
7.50/$11.15


Apr 1 - Dec 31, 09Put

Credit Suisse

NYMEX


10,000

$
8.50


Apr 1 - Dec 31, 09Put

Credit Suisse

NYMEX


28,000

$
6.00


Apr 1 - Dec 31, 09Basis Swap

Credit Suisse

PG&E Citygate


19,625

$
0.00


Apr 1 - Dec 31, 09Swap

Credit Suisse

NYMEX


1,250

$
8.00


Jul 1 - Dec 31, 09Collar

Credit Suisse

NYMEX


1,250

$
7.25/$11.30


Jul 1 - Dec 31, 09Basis Swap

Bank of Montreal

PG&E Citygate


6,475

$
0.14


Apr 1 - Dec 31, 09Collar

Bank of Montreal

NYMEX


1,000

$
7.00/$9.10


Jan 1 - Dec 31, 10Collar

Bank of Montreal

NYMEX


900

$
7.50/$12.20


Jan 1 - Dec 31, 10Put

Bank of Montreal

NYMEX


41,000

$
6.00


Jan 1 - Dec 31, 10Basis Swap

Bank of Montreal

PG&E Citygate


7,718

$
0.09


Jan 1 - Dec 31, 09Collar

Bank of Oklahoma

NYMEX


10,000

$
7.00/$10.35


Jan 1 - Dec 31, 10Basis Swap

Bank of Oklahoma

PG&E Citygate


10,000

$
0.22


Jan 1 - Dec 31, 10Collar

Credit Suisse

NYMEX


6,000

$
7.50/$11.95


Jan 1 - Dec 31, 10Basis Swap

Credit Suisse

PG&E Citygate


7,900

$
0.05


Jan 1 - Dec 31, 10Collar

Credit Suisse

NYMEX


12,000

$
7.50/$13.50


Jan 1 - Dec 31, 11Basis Swap

Credit Suisse

PG&E Citygate


12,000

$
0.03


Jan 1 - Dec 31, 11Put

Credit Suisse

NYMEX


10,000

$
6.00


Jan 1 - Dec 31, 11Put

Key Bank

NYMEX


14,000

$
6.00


Jan 1 - Dec 31, 11Basis Swap

Scotia Capital

PG&E Citygate


6,624

$
0.03


Jan 1 - Dec 31, 11


We enter into derivative contracts, primarily collars, swaps and option contracts, to hedge future crude oil and natural gas production in order
to mitigate the risk of market price fluctuations. Most of our derivative contracts relate to changes in the market price relative to the applicable benchmark price; basis swap contracts relate to
changes in the applicable differential. The objective of our hedging activities and the use of derivative financial instruments is to achieve more predictable cash flows. Our hedging activities
mitigate our exposure to price declines and allow us more flexibility to continue to execute our capital plan even if prices decline. Our collar and swap contracts, however, prevent us from receiving
the full advantage of increases in oil or natural gas prices above the maximum fixed amount specified in the hedge agreement. Also, if production is less than the amount we have hedged and the price
of oil or natural gas exceeds a fixed price in a hedge contract, we will be required to make payments against which there are no offsetting sales of production. This could impact our liquidity and our
ability to fund future capital expenditures. In addition, we have incurred, and may incur in the future, substantial unrealized commodity derivative losses in connection with our hedging activities,
although we do not expect such losses to have a material effect on our liquidity or our ability to fund expected capital expenditures.

In
addition, the use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. Our derivative contracts
are with multiple counterparties to minimize our exposure to any individual counterparty. We generally have netting arrangements with our counterparties that provide for the offset of payables against
receivables from separate derivative arrangements with that counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the
event of default by one of the parties to the agreement. All of the counterparties to our derivative contracts are also lenders, or

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

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

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 March 31,
2009, the fair value of our commodity derivatives was a net asset of $118.5 million.

Interest Rate Derivative Transactions

We are subject to interest rate risk with respect to amounts borrowed under our credit facilities because those amounts bear interest
at variable rates. As of May 5, 2009, there was approximately $500.1 million outstanding under those facilities. We have entered into an interest rate swap transaction to limit our
exposure to changes in interest rates with respect to our second lien term loan facility to lock in our interest cost on $500.0 million of borrowings through June 2010. As a result, amounts
borrowed up to $500.0 million 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 in excess of $500.0 million, which is only $0.1 million at March 31, 2009. As of March 31, 2009, the fair value of our interest rate
derivatives was a liability of $25.2 million.

See
notes to our consolidated financial statements for a discussion of our long-term debt as of March 31, 2009.

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 March 31, 2009. 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
March 31, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART IIOTHER INFORMATION

Item 1.    LEGAL PROCEEDINGS

Not Applicable

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, 2008, 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

|     |  |                                                                                                                                        
|---- |  | ---------------------------------------------------------------------------------------------------------------------------------------
|
|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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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.

May 6,
2009

VENOCO, INC.By:

/s/ TIMOTHY M. MARQUEZ Name:  Timothy M. Marquez
Title:Chairman and Chief Executive OfficerBy:

/s/ TIMOTHY A. FICKER Name:  Timothy A. Ficker
Title:Chief Financial Officer


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