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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, 2011oro

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


Venoco, Inc.

Delaware(State or other jurisdiction of
incorporation or organization)

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

80202-1370(Zip Code)


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

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

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

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

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

Large accelerated filer o

Accelerated filer ý

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

Smaller reporting company o


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

As of March 31, 2011, there were 61,719,333 shares of the issuer's common stock, par value $0.01 per share, issued and outstanding.



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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report on Form 10-Q contains "forward-looking statements" as that term is defined in the Private Securities
Litigation Reform Act of 1995. The use of any statements containing the words "anticipate," "intend," "believe," "estimate," "project," "expect," "plan," "should" or similar expressions are intended
to identify such statements. Forward-looking statements included in this report relate to, among other things, expected future production, expenses and cash flows, the nature, timing and results of
capital expenditure projects, amounts of future capital expenditures, our future debt levels and liquidity, our future compliance with covenants under our revolving credit facility, our pursuit and
receipt of approvals relating to the pipeline project at the South Ellwood field and the maintenance of delivery and sales arrangements relating to production from the South Ellwood field. The
expectations reflected in such forward-looking statements may prove to be incorrect. Disclosure of important factors that could cause actual results to differ materially from our expectations, or
cautionary statements, are included under the heading "Risk Factors" in this report and our Annual Report on Form 10-K for the year ended December 31, 2010. Certain
cautionary statements are also included elsewhere in this report, including, without limitation, in conjunction with the forward-looking statements. All forward-looking statements speak only as of the
date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements.
Except as required by law, we undertake no obligation to update any forward-looking statement. Factors that could cause actual results to differ materially from our expectations include, among others,
those factors referenced in the "Risk Factors" section of this report and our Annual Report on Form 10-K for the year ended December 31, 2010 and such things
as:



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VENOCO, INC.  Form 10-Q for the Quarterly Period Ended March 31, 2011        TABLE OF CONTENTS



PART I.

FINANCIAL INFORMATIONItem 1.

Financial Statements (Unaudited)


2Condensed Consolidated Balance Sheets at December 31, 2010 and March 31, 2011


2Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2010 and the Three
Months Ended March 31, 2011


3Condensed Consolidated Statements of Changes in Stockholders' Equity for the Three Months Ended March 31,
2011


4Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2010 and the Three Months Ended
March 31, 2011


5Notes to Condensed Consolidated Financial Statements


6Item 2.

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


28Item 3.

Quantitative and Qualitative Disclosures about Market Risk


40Item 4.

Controls and Procedures


43PART II.

OTHER INFORMATION


44Item 1.

Legal Proceedings


44Item 1A.

Risk Factors


44Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds


44Item 3.

Defaults upon Senior Securities


44Item 4.

Removed and Reserved


44Item 5.

Other Information


44Item 6.

Exhibits


44Signatures


45


1

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

December 31,
2010

March 31,
2011ASSETSCURRENT ASSETS:Cash and cash equivalents

$
5,024

$
21,598Accounts receivable


29,602


31,169Inventories


6,229


6,583Other current assets


4,585


3,887Income taxes receivable


931


931Commodity derivatives


26,407


25,102Total current assets


72,778


89,270PROPERTY, PLANT AND EQUIPMENT, AT COST:Oil and gas properties, full cost method of accountingProved


1,734,190


1,792,096Unproved


42,686


50,001Accumulated depletion


(1,147,688
)

(1,168,268
)Net oil and gas properties


629,188


673,829Other property and equipment, net of accumulated depreciation and amortization of $16,588 and $17,706 at December 31, 2010 and March 31, 2011,
respectively


18,856


18,168Net property, plant and equipment


648,044


691,997OTHER ASSETS:Commodity derivatives


21,462


18,140Deferred loan costs


6,096


13,891Other


2,543


2,314Total other assets


30,101


34,345TOTAL ASSETS

$
750,923

$
815,612LIABILITIES AND STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities

$
45,396

$
40,326Interest payable


5,538


14,337Commodity and interest derivatives


33,483


26,511Total current liabilities


84,417


81,174LONG-TERM DEBT


633,592


643,443COMMODITY AND INTEREST DERIVATIVES


23,430


16,357ASSET RETIREMENT OBLIGATIONS


93,721


96,215Total liabilities


835,160


837,189COMMITMENTS AND CONTINGENCIESSTOCKHOLDERS' EQUITY:Common stock, $.01 par value (200,000,000 shares authorized; 56,241,672 and 61,719,333 shares issued and outstanding at December 31, 2010 and
March 31, 2011, respectively)


562


617Additional paid-in capital


348,573


435,103Retained earnings (accumulated deficit)


(433,372
)

(457,297
)Total stockholders' equity


(84,237
)

(21,577
)TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
750,923

$
815,612


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 31,2010

2011REVENUES:Oil and natural gas sales

$
81,936

$
78,319Other


820


871Total revenues


82,756


79,190EXPENSES:Lease operating expense


20,850


21,676Production and property taxes


2,222


1,548Transportation expense


1,078


1,986Depletion, depreciation and amortization


19,974


21,691Accretion of asset retirement obligations


1,585


1,590General and administrative, net of amounts capitalized


9,409


9,829Total expenses


55,118


58,320Income (loss) from operations


27,638


20,870FINANCING COSTS AND OTHER:Interest expense, net


10,124


12,697Amortization of deferred loan costs


677


531Interest rate derivative losses (gains), net


9,524


1,083Loss on extinguishment of debt





1,357Commodity derivative losses (gains), net


(36,475
)

29,127Total financing costs and other


(16,150
)

44,795Income (loss) before income taxes


43,788


(23,925
)Income tax provision (benefit)


(200
)

Net income (loss)

$
43,988

$
(23,925
)Earnings per common share:Basic

$
0.83

$
(0.43
)Diluted

$
0.81

$
(0.43
)Weighted average common shares outstanding:Basic


50,993


56,159Diluted


51,920


56,159


See
notes to condensed consolidated financial statements.

3

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

Common Stock



Retained
Earnings
(Accumulated
Deficit)Additional
Paid-in
CapitalShares

Amount

TotalBALANCE AT DECEMBER 31, 2010


56,242

$
562

$
348,573

$
(433,372
)
$
(84,237
)Issuance of stock for cash upon exercise of options


186


2


1,654





1,656Issuance of restricted shares, net of cancellations


685


7


(7
)




Share-based compensation








2,650





2,650Issuance of common stock pursuant to Employee Stock Purchase Plan


6





81





81Issuance of stock, net of underwriters discounts


4,600


46


82,754





82,800Stock issuance costs








(602
)




(602
)Net income (loss)











(23,925
)

(23,925
)BALANCE AT MARCH 31, 2011


61,719

$
617

$
435,103

$
(457,297
)
$
(21,577
)


See
notes to condensed consolidated financial statements.

4

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

Three Months Ended March 31,2010

2011CASH FLOWS FROM OPERATING ACTIVITIES:Net income (loss)

$
43,988

$
(23,925
)Adjustments to reconcile net income (loss) to net cash provided by operating activities:Depletion, depreciation and amortization


19,974


21,691Accretion of asset retirement obligations


1,585


1,590Deferred income tax provision (benefit)


8,400


Share-based compensation


1,323


1,824Amortization of deferred loan costs


677


531Amortization of bond discounts and other non-cash interest


142


162Loss on extinguishment of debt





1,357Unrealized interest rate swap derivative losses (gains)


5,015


(40,064
)Unrealized commodity derivative losses (gains) and amortization of premiums


(33,814
)

34,595Changes in operating assets and liabilities:Accounts receivable


40


(818
)Inventories


476


(354
)Other current assets


(31
)

638Income taxes receivable


(8,600
)

Other assets


(73
)

229Accounts payable and accrued liabilities


(8,492
)

6,688Net premiums paid on derivative contracts


(5,980
)

(3,949
)Net cash provided by operating activities


24,630


195CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for oil and natural gas properties


(42,861
)

(66,907
)Acquisitions of oil and natural gas properties


(2,041
)

(301
)Expenditures for other property and equipment


(445
)

(414
)Proceeds from sale of oil and natural gas properties





Net cash (used in) provided by investing activities


(45,347
)

(67,622
)CASH FLOWS FROM FINANCING ACTIVITIES:Proceeds from long-term debt


50,000


515,000Principal payments on long-term debt


(30,000
)

(505,311
)Payments for deferred loan costs


(134
)

(9,578
)Proceeds from issuance of common stock





82,800Stock issuance costs





(602
)Proceeds from stock incentive plans and other


1,011


1,692Net cash (used in) provided by financing activities


20,877


84,001Net increase (decrease) in cash and cash equivalents


160


16,574Cash and cash equivalents, beginning of period


419


5,024Cash and cash equivalents, end of period

$
579

$
21,598Supplemental Disclosure of Cash Flow InformationCash paid for interest

$
5,487

$
3,742Cash paid for income taxes

$


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

$
16,318

$
17,413Increase (decrease) in accrued capital expenditures

$
1,084

$
(2,959
)


See notes to condensed consolidated financial statements.

5

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

1. SIGNIFICANT ACCOUNTING POLICIES

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

Basis of PresentationThe unaudited condensed consolidated financial statements include the accounts of Venoco and its subsidiaries, all of which
are
wholly owned. The financial statements have been prepared in accordance with U.S. generally accepted accounting principles for interim financial reporting. All significant intercompany balances and
transactions have been eliminated in consolidation. In the opinion of management, all material adjustments considered necessary for a fair presentation of the Company's interim results have been
reflected. The Company has evaluated subsequent events and transactions for matters that may require recognition or disclosure in these financial statements. Venoco's Annual Report on
Form 10-K for the year ended
December 31, 2010 includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this report. The results for interim periods are not
necessarily indicative of annual results.

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

Income TaxesThe Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate
to
its year-to-date income or loss, except for discrete items. Income taxes for discrete items are computed and recorded in the period in which the specific transaction occurs.
The Company incurred losses before income taxes in 2008 and 2009. These losses were a key consideration that led the Company to provide a valuation allowance against its net deferred tax assets at
December 31, 2010 and March 31, 2011 since it could not conclude that it is more likely than not that the net deferred tax assets will be fully realized on future tax returns. As long as
the Company concludes that it will continue to have a need for a full valuation allowance against its net deferred tax assets, the Company likely will not have any income tax expense or benefit other
than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims or for state income taxes. The income tax benefit for the
three months ended March 31, 2010 primarily relates to an increase in the estimated net operating loss carryback claim for the 2003 through 2005 tax years. Due to the valuation allowance, no
income tax expense or benefit was recorded for the three months ended March 31, 2011.

Earnings Per ShareBasic earnings (loss) per share is calculated by dividing net earnings (loss) attributable to common stock by the weighted
average
number of shares outstanding for the period

6

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

(unvested
restricted stock is excluded from the weighted average shares outstanding used in the basic earnings per share calculation). Under the treasury stock method, diluted earnings per share is
calculated by dividing net earnings (loss) by the weighted average number of shares outstanding
including all potentially dilutive common shares (unvested restricted stock and unexercised stock options). In the event of a net loss, no potential common shares are included in the calculation of
shares outstanding, as their inclusion would be anti-dilutive.

Unvested
share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of
earnings per share pursuant to the two-class method. The Company's unvested restricted stock awards contain nonforfeitable dividend rights and participate equally with common stock with
respect to dividends issued or declared. However, the Company's unvested restricted stock does not have a contractual obligation to share in losses of the Company. The Company's unexercised stock
options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating
securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Consequently, in
periods of net loss, the two class method will not have an effect on the Company's basic earnings per share.

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

Three Months
Ended
March 31,2010

2011Dilutive


3,681


Anti-dilutive


1,779


3,649


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

Three Months Ended
March 31,2010

2011Net income (loss)

$
43,988

$
(23,925
)Allocation of net income to unvested restricted stock


(1,853
)

Net income (loss) allocated to common stock

$
42,135

$
(23,925
)Basic weighted average common shares outstanding


50,993


56,159Add: dilutive effect of stock options


927


Diluted weighted average common shares outstanding


51,920


56,159Basic earnings per common share

$
0.83

$
(0.43
)Diluted earnings per common share

$
0.81

$
(0.43
)


7

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

2. ACQUISITIONS AND SALES OF PROPERTIES

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

Sales of Texas Assets.In the second quarter of 2010, the Company sold its interests in its producing properties in Texas ("Texas
Sales") for
$98.1 million (after closing adjustments and related expenses). The Company used the proceeds from the sales to repay $66.9 million of the principal balance on the revolving credit
facility and $30.7 million of the principal balance on the second lien term loan. The Company did not recognize a gain or loss for financial reporting purposes on the sale in accordance with
the full cost method of accounting, but recorded the proceeds from the Texas Sales as a reduction to the capitalized cost of its oil and natural gas properties. As a result of the Texas Sales, the
Company no longer has any interests in producing oil and natural gas properties in Texas. The Company did, however, retain its 22.3% reversionary working interest in the Hastings Complex.

3. LONG-TERM DEBT

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

December 31,
2010

March 31,
2011Revolving credit agreement due January 2013

$
35,000

$
Second lien term loan due May 2014


455,311


11.50% senior notes due October 2017


143,281


143,4438.875% senior notes due February 2019





500,000Total long-term debt


633,592


643,443Less: current portion of long-term debt





Long-term debt, net of current portion

$
633,592

$
643,443


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

8

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

3. LONG-TERM DEBT (Continued)

other
times at the Company's request or at the request of the lenders. The facility is secured by a first priority lien on substantially all of the Company's oil and natural gas properties and other
assets, including the equity interests in all of the Company's subsidiaries, and is unconditionally guaranteed by each of the Company's operating subsidiaries other than Ellwood Pipeline, Inc.
The collateral also secures the Company's obligations to hedging counterparties that are also lenders, or affiliates of lenders, under the facility. Loans made under the revolving credit facility are
designated, at the Company's option, as either "Base Rate Loans" or "LIBO Rate Loans." Loans designated as Base Rate Loans under the facility bear interest at a floating rate equal to (i) the
greater of (x) the Bank of Montreal's announced base rate, (y) the overnight federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.0%, plus (ii) an
applicable margin ranging from 0.75% to 1.75%, based on utilization. Loans designated as LIBO Rate Loans under the facility bear interest at (i) LIBOR plus (ii) an applicable margin
ranging from 1.75% to 2.75%, based upon utilization. A commitment fee of 0.50% per annum is payable with respect to unused borrowing availability under the facility. The agreement governing the
facility contains customary representations, warranties, events of default, indemnities and covenants, including operational covenants that restrict the Company's ability to incur indebtedness and
financial covenants that require the Company to maintain specified ratios of current assets to current liabilities and debt to EBITDA.

The
borrowing base under the revolving credit facility has been allocated at various percentages to a syndicate of 11 banks. Certain of the institutions included in the syndicate have
received support from governmental agencies in connection with events in the credit markets.

In
February 2011, the Company repaid the outstanding balance of the revolving credit facility with proceeds from an issuance of common stock (see note 7). As of May 4,
2011, the Company had no balance outstanding on the facility and had available borrowing capacity of $196.2 million under the facility, net of $3.8 million in outstanding letters of
credit.

Second lien term loan facility and 8.875% senior notes.In May 2007, the Company entered into a $500.0 million senior secured
second lien term
loan facility (the "second lien term loan facility"), which was due to mature on May 8, 2014. Prior to repayment of the second lien term loan facility in February 2011 (see below), loans made
under the second lien term loan facility were designated, at the Company's option, as either "Base Rate Loans" or "LIBO Rate Loans." Loans designated as Base Rate Loans bore interest at a floating
rate equal to (i) the greater of the overnight federal funds rate plus 0.50% and a market base rate, plus (ii) 3.00%. Loans designated as LIBO Rate Loans bore interest at LIBOR plus
4.00%.

The
facility was 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 was unconditionally guaranteed by each of the Company's subsidiaries other than Ellwood Pipeline, Inc.

In
February 2011, the Company issued $500 million in 8.875% senior notes due in February 2019 at par. Concurrently with the sale of the 8.875% senior notes, the Company repaid in
full the outstanding principal balance of $455.3 million on the second lien term loan, plus accrued interest of $1.6 million. The 8.875% senior notes pay interest
semi-annually in arrears on February 15 and August 15 of each year. The Company may redeem the notes prior to February 15, 2015 at a "make whole premium" defined in
the indenture. Beginning February 15, 2015, the Company may redeem the

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

3. LONG-TERM DEBT (Continued)

notes
at a redemption price of 104.438% of the principal amount and declining to 100% by February 15, 2017. The 8.875% senior notes are senior unsecured obligations and contain operational
covenants that, among other things, limit the Company's ability to make investments, incur additional indebtedness, issue preferred stock, pay dividends, repurchase its stock, create liens or sell
assets.

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

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

The
Company was in compliance with all debt covenants at March 31, 2011.

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS

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

The
use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company's derivative contracts are
with multiple counterparties to minimize exposure to any individual counterparty. The Company generally has netting arrangements with the counterparties that provide for the offset of payables against
receivables from separate derivative arrangements with that counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the
event of default by one of the parties to the agreement. All of the counterparties to the Company's derivative contracts are also lenders, or affiliates of lenders, under its revolving credit
facility. Collateral under the revolving credit facility supports the Company's collateral obligations under the Company's derivative contracts. Therefore, the Company is not required to post
additional collateral when the Company is in a derivative liability position. The Company's revolving credit facility and derivative contracts contain provisions that provide for cross defaults and
acceleration of those debt and derivative instruments in certain situations.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

The
Company has elected not to apply hedge accounting to any of its derivative transactions and, consequently, the Company recognizes mark-to-market gains and
losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income for those commodity derivatives that would qualify as cash flow hedges.

The
Company has paid premiums related to certain of its outstanding derivative contracts. These premiums are amortized into commodity derivative (gains) losses over the period for which
the contracts are effective. At March 31, 2011, the balance of unamortized net derivative premiums paid was $17.2 million, of which $6.0 million, $9.5 million and
$1.7 million will be amortized in the remainder of 2011 and in 2012 and 2013, respectively.

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

Three Months Ended
March 31,2010

2011Realized commodity derivative (gains) losses

$
(2,661
)
$
(5,468
)Amortization of commodity derivative premiums


5,657


1,990Unrealized commodity derivative (gains) losses for changes in fair value:


(39,471
)

32,605Commodity derivative (gains) losses

$
(36,475
)
$
29,127


As
of March 31, 2011, the Company had entered into various swap, collar and option agreements related to its oil and natural gas production. The aggregate economic effects of
those agreements are summarized below. Location and quality differentials attributable to the Company's properties are not included in the following prices. The agreements provide for monthly
settlement based on the

11

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

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

Oil
(NYMEX WTI)

Natural Gas
(NYMEX Henry Hub)Weighted
Avg.
Barrels/day

Weighted Avg.
Prices per Bbl

Weighted
Avg.
MMBtu/day

Weighted Avg.
Prices per
MMBtuApril 1 - December 31, 2011:Swaps


2,400

$
105.65


24,000

$
4.44Collars(1)


5,000

$
50.00/$100.00




$
Puts(1)


2,000

$
50.00


36,000

$
5.92January 1 - December 31, 2012:Collars


8,500

$
75.29/$118.84




$
Puts




$



37,300

$
5.81January 1 - December 31, 2013:Collars


3,900

$
81.79/113.59


20,000

$
5.00/$7.02


---

The
Company has also entered into certain oil and natural gas basis swaps. The oil basis swaps fix the differential between the NYMEX WTI crude price index ("WTI") and the
Inter-Continental Exchange Brent crude price index ("Brent"). Historically the two price indexes have demonstrated a close correlation. The Southern California indexes on which the Company sells a
significant percentage of its oil have historically demonstrated a close correlation with these two major crude oil benchmarks. Recently, however, the relationship between WTI and Brent has diverged,
favoring Brent crude, and the Southern California indexes most relevant to the Company have continued to track their correlation to Brent prices. The oil basis swaps entered into by the Company
attempt to fix the current premium Southern California indexes are realizing relative to WTI and hedge the effect of future changes to the WTI-Brent relationship. The natural gas basis
swaps fix the differential between the Henry Hub price and the PG&E Citygate price, the index on which the majority of the Company's natural gas is sold. The Company's oil and natural gas basis swaps
as of March 31, 2011 are presented below:

Oil Basis Swaps
(NYMEX WTI)

Natural Gas Basis Swaps
(NYMEX Henry Hub)Floating Index

Weighted Avg.
Bbls/Day

Weighted
Avg. Basis
Differential to
NYMEX WTI
(per Bbl)

Floating Index

Weighted Avg.
MMBtu/Day

Weighted
Avg. Basis
Differential to
NYMEX HH
(per MMBtu)Basis Swaps:April 1 - December 31, 2011

Brent Crude


3,700

$
9.30

PG&E Citygate


57,224

$
0.11January 1 - December 31, 2012

Brent Crude


7,630

$
6.90

PG&E Citygate


47,400

$
0.28January 1 - December 31, 2013

Brent Crude


3,900

$
5.88






$



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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

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

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

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

Three Months Ended
March 31,2010

2011Realized interest rate derivative (gains) losses

$
4,509

$
41,147Unrealized interest rate derivative (gains) losses


5,015


(40,064
)Interest rate derivative (gains) losses, net

$
9,524

$
1,083


Fair Value of Derivative Instruments.The estimated fair values of derivatives included in the consolidated balance sheets at
December 31,
2010 and March 31, 2011 are summarized below. The net fair value of the Company's derivatives changed by $9.4 million from a net liability of $9.0 million at December 31,
2010 to a net asset of $0.4 million at March 31, 2011, primarily due to (i) settlement of the interest rate swaps in February 2011, (ii) changes in the futures prices for
oil and natural gas, which are used in the calculation of the fair value of commodity derivatives and (iii) changes to the Company's commodity derivative portfolio during 2011. The Company does
not offset asset and liability positions with the same counterparties within the financial statements, rather, all contracts are presented at their gross estimated fair value. As of the dates
indicated, the Company's derivative assets and liabilities are presented below (in thousands). These balances represent the estimated fair value of

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

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

December 31,
2010

March 31,
2011Current AssetsCommodity derivatives:Oil derivative contracts

$
95

$
1,474Gas derivative contracts


26,312


23,62826,407


25,102Other AssetsCommodity derivatives:Oil derivative contracts





1,940Gas derivative contracts


21,462


16,20021,462


18,140Current LiabilitiesCommodity and interest derivatives:Oil derivative contracts


(8,039
)

(21,301
)Gas derivative contracts


(6,890
)

(5,210
)Interest rate derivative contracts


(18,554
)

(33,483
)

(26,511
)Commodity and interest derivatives:Oil derivative contracts


(1,921
)

(16,357
)Gas derivative contracts





Interest rate derivative contracts


(21,509
)

(23,430
)

(16,357
)Net derivative asset (liability)

$
(9,044
)
$
374


5. FAIR VALUE MEASUREMENTS

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

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

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

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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 and for substantially the full term of the instrument. Inputs may include quoted prices for similar assets and liabilities. Level 2 includes those financial instruments that are valued
using models or other valuation methodologies.

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

Financial
assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the
significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value
hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of March 31,
2011 (in thousands).

Level 1

Level 2

Level 3

Fair Value
as of
March 31,
2011Assets (Liabilities):Commodity derivative contracts

$


$
43,242

$


$
43,242Commodity derivative contracts





(42,868
)




(42,868
)


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

Commodity Derivative Contracts.The Company's commodity derivative instruments consist primarily of swaps, collars and option contracts
for oil and
natural gas. The Company values the derivative contracts using industry standard models, based on an income approach, which considers various assumptions including quoted forward prices and
contractual prices for the underlying commodities, time value and volatility factors, as well as other relevant economic measures. Substantially all of the assumptions can be observed throughout the
full term of the contracts, can be derived from observable data or are supportable by observable levels at which transactions are executed in the marketplace and are therefore designated as
level 2 within the fair value hierarchy. The discount rates used in the assumptions include a component of non-performance risk. The Company utilizes the relevant counterparty
valuations to assess the reasonableness of the calculated fair values.

Interest Rate Derivative Contracts.The Company's interest rate swaps were valued using an industry standard model, based on an income
approach that
utilized quoted forward prices for interest rates, time value and contractual interest rates per the swap contract. The discount rates used in the assumption include a component of
non-performance risk. The interest rate swaps were designated as level 2 within the fair value hierarchy. The Company utilized the relevant counterparties' valuations to assess the
reasonableness of the calculated fair values. The Company settled its outstanding interest rate derivative contracts in February 2011.

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

5. FAIR VALUE MEASUREMENTS (Continued)

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

December 31, 2010

March 31, 2011Carrying
Value

Estimated
Fair Value

Carrying
Amount

Estimated
Fair ValueRevolving credit agreement

$
35,000

$
35,000

$


$
Second lien term loan


455,311


434,253





11.50% senior notes


143,281


162,000


143,443


166,8758.875% senior notes








500,000


505,000


6. ASSET RETIREMENT OBLIGATIONS

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

16

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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, 2010 and 2011 (in thousands):

Three Months
Ended
March 31, 2010

Three Months
Ended
March 31, 2011Asset retirement obligations at beginning of period

$
92,985

$
94,221Revisions of estimated liabilities


309


(75
)Liabilities incurred/acquired


1,216


979Liabilities settled


(1,127
)

Accretion expense


1,585


1,590Asset retirement obligations at end of period


94,968


96,715Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)


(1,000
)

(500
)Long-term asset retirement obligations

$
93,968

$
96,215


7. CAPITAL STOCK

The Company has 65.9 million shares of common stock issued or reserved for issuance at March 31, 2011. At March 31, 2011, the Company has 61.7 million common
shares issued and outstanding, of which 3.0 million shares are restricted stock granted under the Company's 2005 stock incentive plan. At March 31, 2011, the Company had approximately
0.9 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.

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

8. SHARE-BASED PAYMENTS

The Company has granted options to directors, certain employees and officers of the Company, other than its CEO, under its 2000 and 2005 Stock Plans (the "Stock Plans"). As of
March 31, 2011, there are a total of 908,005 options outstanding with a weighted average exercise price of $13.92 ($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.

The
Company provides a non-compensatory Employee Stock Purchase Plan (the "ESPP"), for which 1.4 million authorized shares of common stock are available for issuance.
Participation in the ESPP is open to all employees, other than executive officers, who meet limited qualifications. Under the terms of the ESPP, employees are able to purchase Company stock at a 5%
discount as determined by the fair market value of the Company's stock on the last trading day of each purchase period. Individual employees are limited to $25,000 of common stock purchased in any
calendar year.

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

8. SHARE-BASED PAYMENTS (Continued)

As
of March 31, 2011, there were a total of 3,042,790 shares of restricted stock outstanding under the Company's 2005 stock incentive plan, including 1,070,495 shares granted to
its CEO. Restricted shares subject to service conditions only generally vest over a four year period, with 25% vesting on each subsequent anniversary of the grant date. The grant date fair value of
restricted stock subject to service conditions only is determined by the Company's closing stock price on the day prior to the date of grant. The vesting of 1,917,030 shares is also subject to market
conditions based on the Company's total shareholder return in comparison to peer group companies and/or an industry index for each calendar year. Shares of restricted stock subject to market
conditions which were granted prior to 2011 have a four year period over which vesting may occur. For grants issued in 2011, this period was expanded by three years in which a portion of the available
shares could vest. The weighted-average fair value of the restricted shares subject to market conditions was derived using a Monte Carlo technique. The weighted average fair value of 496,846 awards
with market conditions granted in February 2011 was estimated to be $17.83 per share. The estimated grant date fair values of restricted share awards are recognized as expense over the requisite
service periods. The Company's total shareholder return for the measurement period for the year ended December 31, 2010 was below the minimum threshold for vesting to occur. Therefore, none of
the market based restricted shares vested for this measurement period and 54,845 shares were forfeited as they were in the fourth and final year of the vesting cycle.

As
of March 31, 2011, there was $0.1 million of total unrecognized compensation cost related to stock options, which is expected to be amortized over a weighted-average
period of 0.3 years, and $25.8 million of total unrecognized compensation cost related to restricted stock, which is expected to be amortized over a weighted-average period of
3.2 years.

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

Three Months Ended
March 31,2010

2011General and administrative expense

$
1,640

$
2,280Oil and natural gas production expense


240


370Total share-based compensation costs


1,880


2,650Less: share-based compensation costs capitalized


(557
)

(826
)Share-based compensation expensed

$
1,323

$
1,824


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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

8. SHARE-BASED PAYMENTS (Continued)

The
following summarizes the Company's stock option activity for the three months ended March 31, 2011:

Options

Weighted
Average
Exercise
PriceOutstanding, start of period


1,093,758

$
13.07Granted




$
Exercised


(185,753
)
$
9.69Cancelled




$
Outstanding, end of period


908,005

$
13.92Exercisable, end of period


880,505

$
13.79


The
following summarizes the Company's unvested restricted stock award activity for the three months ended March 31, 2011:

Shares

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


2,603,250

$
9.70Granted


756,431

$
17.44Vested


(246,278
)
$
9.86Forfeited


(70,613
)
$
13.17Non-vested, end of period


3,042,790

$
11.53


9. CONTINGENCIES



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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

9. CONTINGENCIES (Continued)

plaintiffs
on the grounds that they offered no evidence of medical causation between the alleged emissions and the plaintiffs' alleged injuries. Plaintiffs appealed the ruling. A decision on the
appeal is expected in 2011. The Company vigorously defended the actions, and will continue to do so until they are resolved. Certain defendants have made claims for indemnity which the Company is
disputing. The Company cannot predict the cost of these indemnity claims at the present time.

One
of the Company's insurers is currently paying for the defense of these lawsuits under a reservation of its rights. If the insurer ceases to provide such defense, and the Company is
unsuccessful in enforcing its rights in any subsequent litigation, the Company will be required to bear the costs of the defense, and those costs may be material. If it ultimately is determined that
the pollution exclusion or another exclusion contained in one or more of the Company's policies applies, the Company will not have the protection of those policies with respect to any expenses,
damages or settlement costs ultimately incurred in the lawsuits.

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



In 2004 the California State Lands Commission (the "SLC") initiated an audit of the Company's royalty payments for the period from
August 1, 1997 through December 31, 2003 on oil and gas produced from the South Ellwood Field, State Leases 3120 and 3240 (the "Leases"). The audit period was subsequently extended
through September 2009. In December 2009, the Company was notified that the SLC's audit for the period January 2004 through September 2009 indicated that the Company underpaid royalties due on oil and
gas production from the Leases by approximately $5.8 million. In March 2011 the SLC notified the Company that for the period 1997 through 2009 the total underpaid royalties from the Leases were
approximately $5.9 million. Based on the Company's review of the SLC's audit contentions and additional historical records, the Company believes that it may have overpaid royalties due on oil
and gas production during the audit periods and may be owed a refund of such overpayments. The Company believes the position of the SLC is without merit and intends to vigorously contest the audit
findings and to enforce its rights for refunds of royalties it may have overpaid. The Company has not accrued any amounts related to the SLC audit contentions or potential refunds.



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

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION

All subsidiaries of the Company other than Ellwood Pipeline Inc. ("Guarantors") have fully and
unconditionally guaranteed, on a joint and several basis, the Company's obligations under its 11.50% and 8.875% senior notes. Ellwood Pipeline, Inc. is not a Guarantor (the
"Non-Guarantor Subsidiary"). The condensed consolidating financial information for prior periods has been revised to reflect the guarantor and non-guarantor status of the
Company's subsidiaries as of March 31, 2011. All Guarantors are 100% owned by the Company. Presented below are the Company's condensed consolidating balance sheets, statements of operations and
statements of cash flows as required by Rule 3-10 of Regulation S-X of the Securities Exchange Act of 1934.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedASSETSCURRENT ASSETS:Cash and cash equivalents

$
5,024

$


$


$


$
5,024Accounts receivable


29,082


121


399





29,602Inventories


6,229











6,229Other current assets


4,585











4,585Income taxes receivable


931











931Commodity derivatives


26,407











26,407TOTAL CURRENT ASSETS


72,258


121


399





72,778PROPERTY, PLANT & EQUIPMENT, NET


825,844


(183,940
)

6,140





648,044COMMODITY DERIVATIVES


21,462











21,462INVESTMENTS IN AFFILIATES


520,958








(520,958
)

OTHER


8,578


61








8,639TOTAL ASSETS

$
1,449,100

$
(183,758
)
$
6,539

$
(520,958
)
$
750,923LIABILITIES AND STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities

$
45,346

$
50

$


$


$
45,396Interest payable


5,538











5.538Commodity and interest derivatives


33,483











33,483TOTAL CURRENT LIABILITIES:


84,367


50








84,417LONG-TERM DEBT


633,592











633,592COMMODITY AND INTEREST DERIVATIVES


23,430











23,430ASSET RETIREMENT OBLIGATIONS


91,127


1,604


990





93,721INTERCOMPANY PAYABLES (RECEIVABLES)


700,821


(650,346
)

(50,475
)




TOTAL LIABILITIES


1,533,337


(648,692
)

(49,485
)




835,160TOTAL STOCKHOLDERS' EQUITY


(84,237
)

464,934


56,024


(520,958
)

(84,237
)TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
1,449,100

$
(183,758
)
$
6,539

$
(520,958
)
$
750,923


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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS  AT MARCH 31, 2011 (Unaudited)  (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedASSETSCURRENT ASSETS:Cash and cash equivalents

$
21,598

$


$


$


$
21,598Accounts receivable


30,645


149


375





31,169Inventories


6,583











6,583Other current assets


3,887











3,887Income tax receivable


931











931Commodity derivatives


25,102











25,102TOTAL CURRENT ASSETS


88,746


149


375





89,270PROPERTY, PLANT & EQUIPMENT, NET


869,903


(183,973
)

6,067





691,997COMMODITY DERIVATIVES


18,140











18,140INVESTMENTS IN AFFILIATES


522,885








(522,885
)

OTHER


16,144


61








16,205TOTAL ASSETS

$
1,515,818

$
(183,763
)
$
6,442

$
(522,885
)
$
815,612LIABILITIES AND STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities

$
40,265

$
61

$


$


$
40,326Interest payable


14,337











14,337Commodity and interest derivatives


26,511











26,511TOTAL CURRENT LIABILITIES:


81,113


61








81,174LONG-TERM DEBT


643,443











643,443COMMODITY AND INTEREST DERIVATIVES


16,357











16,357ASSET RETIREMENT OBLIGATIONS


93,571


1,636


1,008





96,215INTERCOMPANY PAYABLES (RECEIVABLES)


702,911


(650,848
)

(52,063
)




TOTAL LIABILITIES


1,537,395


(649,151
)

(51,055
)




837,189TOTAL STOCKHOLDERS' EQUITY


(21,577
)

465,388


57,497


(522,885
)

(21,577
)TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
1,515,818

$
(183,763
)
$
6,442

$
(522,885
)
$
815,612


23

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS  THREE MONTHS ENDED MARCH 31, 2010 (Unaudited)  (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
74,916

$
7,020

$


$


$
81,936Other


696


36


1,259


(1,171
)

820Total revenues


75,612


7,056


1,259


(1,171
)

82,756EXPENSES:Lease operating expenses


18,556


1,938


356





20,850Production and property taxes


1,970


250


2





2,222Transportation expense


2,153


10





(1,085
)

1,078Depletion, depreciation and amortization


18,565


1,278


131





19,974Accretion of asset retirement obligations


1,445


123


17





1,585General and administrative, net of amounts capitalized


8,766


625


104


(86
)

9,409Total expenses


51,455


4,224


610


(1,171
)

55,118Income (loss) from operations


24,157


2,832


649





27,638FINANCING COSTS AND OTHER:Interest expense, net


11,045





(921
)




10,124Amortization of deferred loan costs


677











677Interest rate derivative losses (gains), net


9,524











9,524Commodity derivative losses (gains), net


(36,475
)










(36,475
)Total financing costs and other


(15,229
)




(921
)




(16,150
)Equity in subsidiary income


2,729








(2,729
)

Income (loss) before income taxes


42,115


2,832


1,570


(2,729
)

43,788Income tax provision (benefit)


(1,873
)

1,076


597





(200
)Net income (loss)

$
43,988

$
1,756

$
973

$
(2,729
)
$
43,988


24

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS  THREE MONTHS ENDED MARCH 31, 2011 (Unaudited)  (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
77,933

$
386

$


$


$
78,319Other


784


14


1,094


(1,021
)

871Total revenues


78,717


400


1,094


(1,021
)

79,190EXPENSES:Lease operating expenses


21,282


23


371





21,676Production and property taxes


1,683


(135
)







1,548Transportation expense


2,919








(933
)

1,986Depletion, depreciation and amortization


21,523


26


142





21,691Accretion of asset retirement obligations


1,539


32


19





1,590General and administrative, net of amounts capitalized


9,801





116


(88
)

9,829Total expenses


58,747


(54
)

648


(1,021
)

58,320Income (loss) from operations


19,970


454


446





20,870FINANCING COSTS AND OTHER:Interest expense, net


13,723





(1,026
)




12,697Amortization of deferred loan costs


531











531Interest rate derivative losses (gains), net


1,083











1,083Loss on extinguishment of debt


1,357











1,357Commodity derivative losses (gains), net


29,127











29,127Total financing costs and other


45,821





(1,026
)




44,795Equity in subsidiary income


1,194








(1,194
)

Income (loss) before income taxes


(24,657
)

454


1,472


(1,194
)

(23,925
)Income tax provision (benefit)


(732
)

172


560





Net income (loss)

$
(23,925
)
$
282

$
912

$
(1,194
)
$
(23,925
)


25

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS  THREE MONTHS ENDED MARCH 31, 2010 (Unaudited)  (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

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

$
18,367

$
4,506

$
1,757

$


$
24,630CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for oil and natural gas properties


(38,552
)

(1,128
)

(3,181
)




(42,861
)Acquisitions of oil and natural gas properties


(2,041
)










(2,041
)Expenditures for property and equipment and other


(444
)

(1
)







(445
)Net cash provided by (used in) investing activities


(41,037
)

(1,129
)

(3,181
)




(45,347
)CASH FLOWS FROM FINANCING ACTIVITIES:Net proceeds from (repayments of) intercompany borrowings


1,953


(3,377
)

1,424





Proceeds from long-term debt


50,000











50,000Principal payments on long-term debt


(30,000
)










(30,000
)Payments for deferred loan costs


(134
)










(134
)Proceeds from stock incentive plans and other


1,011











1,011Net cash provided by (used in) financing activities


22,830


(3,377
)

1,424





20,877Net increase (decrease) in cash and cash equivalents


160











160Cash and cash equivalents, beginning of period


418


1








419Cash and cash equivalents, end of period

$
578

$
1

$


$


$
579


26

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS  THREE MONTHS ENDED MARCH 31, 2011 (Unaudited)  (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

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

$
(1,957
)
$
496

$
1,656

$


$
195CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for oil and natural gas properties


(66,846
)

7


(68
)




(66,907
)Acquisitions of oil and natural gas properties


(301
)










(301
)Expenditures for property and equipment and other


(414
)










(414
)Net cash provided by (used in) investing activities


(67,561
)

7


(68
)




(67,622
)CASH FLOWS FROM FINANCING ACTIVITIES:Net proceeds from (repayments of) intercompany borrowings


2,091


(503
)

(1,588
)




Proceeds from long-term debt


515,000











515,000Principal payments on long-term debt


(505,311
)










(505,311
)Payments for deferred loan costs


(9,578
)










(9,578
)Proceeds from issuance of common stock


82,800











82,800Stock issuance costs


(602
)










(602
)Proceeds from stock incentive plans and other


1,692











1,692Net cash provided by (used in) financing activities


86,092


(503
)

(1,588
)




84,001Net increase (decrease) in cash and cash equivalents


16,574











16,574Cash and cash equivalents, beginning of period


5,024











5,024Cash and cash equivalents, end of period

$
21,598

$


$


$


$
21,598


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, 2010 as well as with the financial statements and related notes and the
other information appearing elsewhere in this report. As used in this report, unless the context otherwise indicates, references to "we," "our," "ours," and "us" refer to Venoco, Inc. and its
subsidiaries collectively.

Overview

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural
gas properties. Our strategy is to grow through exploration, exploitation and development projects we believe to have the potential to add significant reserves on a cost-effective basis
and through selective acquisitions of underdeveloped properties. In recent years, the exploration, exploitation and development of the onshore Monterey shale formation has taken a fundamental role in
our corporate strategy, and efforts to expand our knowledge of the onshore formation have increased significantly. A substantial portion of our production is from offshore wells targeting the
fractured Monterey shale formation, and we believe that there are significant opportunities relating to the Monterey shale formation onshore as well.

Our
average net production was 17,815 BOE/d in the first quarter of 2011, compared to 19,384 BOE/d in the first quarter of 2010 and 17,328 BOE/d in the fourth quarter of 2010. Excluding
production from producing properties in Texas, which we sold in a series of transactions during the second quarter of 2010, our average net production was 18,096 BOE/d in the first quarter of 2010. As
the sales occurred in the second quarter of 2010, our average net production for the first quarter of 2011 and fourth quarter of 2010 did not reflect any production from Texas.

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

Capital Expenditures

We have developed an active capital expenditure program to take advantage of our extensive inventory of drilling prospects and other
projects. Our current development, exploitation and exploration capital expenditure budget for 2011 is $200 million, of which approximately $64.3 million was expended in the first three
months of 2011. We have currently budgeted approximately 70% or $140 million for Southern California and 30% or $60 million for the Sacramento Basin. Of the $140 million allocated
to Southern California, approximately $100 million is scheduled to be deployed to onshore Monterey shale activities with the remainder going to activities at legacy Southern California fields.
We are currently evaluating our capital expenditure plans for the second half of the year as a result of higher than budgeted costs related to onshore Monterey shale drilling, ongoing data analysis
resulting from that drilling activity and opportunities at legacy fields that are not included in our current 2011 capital expenditure budget. We expect that, during the second quarter, we will
increase our budget modestly in order to pursue additional opportunities at our legacy fields. We expect that the revised budget will contemplate the drilling of 13 net wells targeting the
onshore Monterey shale in 2011. The aggregate levels of capital expenditures for 2011, and the allocation of those expenditures, are dependent on a variety of factors, including the availability of
capital resources to fund the expenditures and changes in our business assessments as to where our capital can be most profitably employed. Accordingly, the actual levels of capital expenditures and
the allocation of those

28

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Table of Contents

expenditures
may vary materially from our estimates. The following summarizes certain significant aspects of our 2011 capital spending program to date and the current outlook for the remainder of 2011
based on our current budget.

Southern CaliforniaExploitation and Development

In the West Montalvo field, we have pursued an active workover, recompletion and return to production program that has resulted in
significant production gains since we acquired the field in May 2007. The field has not been fully delineated offshore or fully developed onshore and we continue to evaluate our drilling
results and refine our development program for the coming years. During the first quarter of 2011, we completed a successful recompletion of an offshore well. We have secured permits to drill seven
offshore and two onshore wells and plan to drill at least two of these locations later in the year.

In
the Sockeye field, activity levels were minimal during the first quarter but we have subsequently begun workover and drilling activities that we expect to complete during the second
quarter. Our current 2011 capital expenditure budget contemplates minimal activity levels at Sockeye during the second half of the year.

At
the South Ellwood field, we continue to work on advancing the permitting process for three of the five proved undeveloped locations on our existing leases and continue to perform the
facilities work necessary to begin drilling those locations. Our 2011 capital expenditure budget includes plans to perform six recompletions and spud one of our proved undeveloped locations at South
Ellwood.

In
addition, our subsidiary Ellwood Pipeline, Inc. is pursuing the permits necessary to build a common carrier pipeline that would allow us to transport our oil from the South
Ellwood field to refiners without the use of a barge or the marine terminal we currently use. We anticipate that approval hearings for the project will be held during mid-2011. While we
believe the pipeline should be approved, the outcome of these hearings cannot be predicted. Pending completion of the pipeline, we expect to continue to use a double-hulled barge to transport oil
production from the field. A draft environmental impact report (the "EIR") for the pipeline project was released in early March 2011. After the statutory review period of the draft, the EIR contractor
will consider comments submitted prior to issuing a final EIR.

Southern CaliforniaOnshore Monterey Shale

In 2006, we began actively leasing onshore acreage in Southern California targeting the Monterey shale, a Miocene age strata. Our
leasing has focused on areas where we believe the Monterey shale will produce light, sweet oil, and where the quality and depth of the Monterey shale is expected to be advantageous. To date, our
onshore Monterey shale acreage position totaled approximately 240,000 gross and 159,000 net acres. An additional 60,000 gross and 46,000 net acres with Monterey shale production or potential are held
by production.

In
2010, we began actively drilling in a few of our more than 30 onshore Monterey shale prospects in three basins: Santa Maria, Salinas Valley, and San Joaquin. We spud 12 wells in 2010,
including eight vertical "science" wells from which we collected cores, gathered a full suite of logs and performed production tests on prospective intervals. We have used various completion
techniques on these wells, including acidizing and fracture stimulations. The remaining four wells spud in 2010 were horizontal wells intended to be completed as producing wells. During the first
quarter of 2011 we spud five new wells, including one horizontal well, and set casing on three wells. In total, since the beginning of 2010 through the first quarter of 2011, we have spud 17 wells (12
vertical and five horizontal), of which 11 have had casing set (seven vertical and four horizontal) and two wells, both vertical, were used as pilot holes for two horizontal wells. Subsequent to the
end of the first quarter, two vertical wells have had casing set, one horizontal well is waiting on casing to be set, and one vertical well is in the process of

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Table of Contents

drilling.
We have been encouraged by the scientific information collected thus far, particularly in two of our prospect areas, but to date have not seen significant production as a result of our
drilling.

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

We
currently have three drilling rigs operating in the onshore Monterey shale, all of which are capable of drilling horizontal wells. We also plan to complete evaluation of the second
and final phase of what we believe to be California's largest 3D seismic shoot during the first half of 2011 and to continue leasing throughout the year.

Sacramento BasinExploitation and Development

In the Sacramento Basin, we continue to pursue our infill drilling program in the greater Grimes and Willows fields. During the first
three months of 2011, we spud 14 wells and performed 46 recompletions in the basin. We continue to test and evaluate potential downspacing opportunities in the basin as well as new methods of
improving productivity and reducing drilling costs.
We also continue to pursue our hydraulic fracturing program in the basin and saw production gains from the five wells we fractured during the first three months of 2011. Also during the first quarter,
we had success drilling an anomaly which we discovered using 3-D seismic data we acquired with leasehold in 2009. The exploratory well had an initial net production rate of more than
three million cubic feet of natural gas per day and has enabled us to extend the boundaries of the Grimes field. We spud two additional anomalies identified with the seismic, one of which was
successful.

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

Acquisitions and Divestitures

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

Sale of Texas Assets.We sold our producing assets in Texas in a series of transactions that were completed in the second quarter of
2010 to multiple
purchasers for aggregate net proceeds of $98.1 million (after closing adjustments and related expenses). We retained our 22.3% reversionary working interest in the Hastings Complex.

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

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Table of Contents

Trends Affecting our Results of Operations

Oil and Natural Gas Prices.Historically, prices received for our oil and natural gas production have been volatile and unpredictable,
and that
volatility is expected to continue. Changes in the market prices for oil and natural gas directly impact many aspects of our business, including our financial condition, revenues, results of
operations, liquidity, rate of growth, the carrying value of our oil and natural gas properties and borrowing capacity under our revolving credit facility, all of which depend in part upon those
prices. We employ a hedging strategy in order to reduce the variability of the prices we receive for our production and provide a minimum revenue stream. As of May 4, 2011 we had hedge contract
floors covering approximately 99% of our 2011 annual production guidance. We have also secured hedge contracts for portions of our 2012 and 2013 production. All of our derivatives counterparties are
members, or affiliates of members, of our revolving credit facility syndicate. See "Quantitative and Qualitative Disclosures About Market RiskCommodity Derivative Transactions" for
further details concerning our hedging activities.

Expected Production.In 2010, we began to emphasize our oil projects in Southern California relative to our natural gas projects in the
Sacramento
Basin. We believe that execution of our expected capital expenditure plan will result in a modest increase in average daily production volumes in 2011, relative to 2010. Although we have projected
growth from our onshore Monterey shale project in 2011, we have not yet seen significant production from the project. In addition, we expect some delays in completing subsequent wells due to the
current limited availability of field services. We therefore expect a smaller contribution to our full-year production from the onshore Monterey shale project than originally anticipated, though we
continue to have positive long-term expectations related to the project. If the project is ultimately successful, we believe that it could result in significant production growth in subsequent years.
Our expectations with respect to future production rates are subject to a number of uncertainties, including those associated with third party services, the availability of drilling rigs, oil and
natural gas prices, events resulting in unexpected downtime, permitting issues, drilling success rates, including our ability to identify productive intervals and the drilling and completion
techniques necessary to achieve commercial production in the onshore Monterey shale, and other factors, including those referenced in the "Risk Factors" section of our Annual Report on
Form 10-K for the year ended December 31, 2010.

Lease Operating Expenses.Lease operating expenses ("LOE") of $13.52 per BOE for the first quarter of 2011 were higher than our full
year 2010
results of $12.65 per BOE. We expect our 2011 LOE per BOE to be higher relative to 2010, primarily due to our expected focus on oil projects, which tend to have higher operating costs than natural gas
projects. Our expectations with respect to future expenses are subject to numerous risks and uncertainties, including those described and referenced in the preceding paragraph.

General and Administrative Expenses.General and administrative expenses increased slightly from $4.78 per BOE for 2010 (excluding
share-based
compensation charges of $0.68 per BOE and one-time charges of $0.19 per BOE for severance payments resulting from the sale of our Texas producing properties), to $5.22 per BOE (excluding
share-based compensation charges of $0.91 per BOE) in the first quarter of 2011. Excluding share-based compensation charges, on a per BOE basis, we expect our G&A costs to be relatively flat in 2011
compared to 2010. As with our lease operating expenses and production and property taxes, our expectations with respect to G&A costs are subject to numerous risks and uncertainties.

Depreciation, Depletion and Amortization (DD&A).DD&A for the first quarter of 2011 of $13.53 per BOE increased from our full
year 2010 DD&A of
$11.79 per BOE. We expect our 2011 DD&A to increase modestly on a per BOE basis compared to our full year 2010 results. As with lease operating expenses, production and property taxes and G&A
expenses, our expectations with respect to DD&A expenses are subject to numerous risks and uncertainties.

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Table of Contents

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

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

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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, 2010 and 2011. This information reflects the actual historical results of our operations. No pro forma
adjustments have been made for acquisitions and divestitures of oil and gas properties, which will affect the comparability of the data below.

Three Months
Ended
March 31,2010

2011Production Volume:Oil (MBbls)(1)


781


608Natural gas (MMcf)


5,781


5,972MBOE


1,745


1,603Daily Average Production Volume:Oil (Bbls/d)


8,678


6,756Natural gas (Mcf/d)


64,233


66,356BOE/d


19,384


17,815Oil Price per Bbl Produced (in dollars):Realized price

$
68.56

$
86.38Realized commodity derivative gain (loss)


(1.38
)

(1.51
)Net realized price

$
67.18

$
84.87Natural Gas Price per Mcf (in dollars):Realized price

$
5.34

$
4.03Realized commodity derivative gain (loss)


0.65


1.07Net realized price

$
5.99

$
5.10Expense per BOE:Lease operating expenses

$
11.95

$
13.52Production and property taxes


1.27


0.97Transportation expenses


0.62


1.24Depreciation, depletion and amortization


11.45


13.53General and administrative expense(2)


5.39


6.13Interest expense


5.80


7.92






Comparison of Quarter Ended March 31, 2011 to Quarter Ended March 31, 2010

Oil and Natural Gas Sales.Oil and natural gas sales decreased by $3.6 million (4%) in the first quarter of 2011 to
$78.3 million
compared to $81.9 million in the first quarter of 2010. Sales in the first quarter of 2011 were affected by decreases in natural gas prices and lower oil production (as described below)
compared to the first quarter of 2010, partially offset by increases in oil prices.

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Oil
sales increased by $3.2 million (6%) in the first quarter of 2011 to $54.3 million compared to $51.1 million in the first quarter of 2010. Oil production
decreased by 22%, with production of 608 MBbls in the first quarter of 2011 compared to 781 MBbls in the first quarter of 2010. The production decrease was primarily due to the sales of our producing
properties in Texas in the second quarter of 2010. Excluding production from the Texas properties, production decreased by 96 MBbls (14%) from 704 MBbls in the first quarter of 2010 to 608 MBbls in
the first quarter of 2011. This decrease is primarily due to natural production decline from the Sockeye, South Ellwood and West Montalvo fields. Our average realized price for oil increased $17.82
per Bbl (26%) from $68.56 per Bbl in the first quarter of 2010 to $86.38 per Bbl for the first quarter of 2011.

Natural
gas sales decreased $6.8 million (22%) in the first quarter of 2011 to $24.1 million compared to $30.9 million in the first quarter of 2010. Natural gas
production increased 3%, with production of 5,972 MMcf in the first quarter of 2011 compared to 5,781 MMcf in the first quarter of 2010. The increase is primarily the result of successful drilling and
recompletion activity in the Sacramento Basin in the latter half of 2010 and first quarter of 2011. Our average realized price for natural gas decreased $1.31 per Mcf (25%) from $5.34 per Mcf in the
first quarter of 2010 to $4.03 per Mcf in the first quarter of 2011.

Other Revenues.Other revenues increased by $0.1 million (6%) to $0.9 million in the first quarter of 2011 from
$0.8 million in
the first quarter of 2010. The increase is primarily due to a contract that became effective April 2010, related to the double-hulled barge that transports oil produced at our South Ellwood field (see
"Transportation Expenses"). The contract allows us to sub-charter the barge and retain the revenues from those activities. The
increase in other revenues is the result of sub-charter activities in the first quarter of 2011.

Lease Operating Expenses.Lease operating expenses ("LOE") increased $0.8 million (4%) to $21.7 million in the first quarter
of 2011
from $20.9 million in the first quarter of 2010. Excluding the Texas properties, production expenses increased $2.8 million (15%) from $18.9 million in the first quarter of 2010
to $21.7 million in the first quarter of 2011. The increase was primarily due to a reduction in oil inventory levels, which resulted in the recognition of the associated lifting costs in the
income statement in the first quarter of 2011. On a per unit basis, LOE increased by $1.57 per BOE from $11.95 in the first quarter of 2010 to $13.52 in the first quarter of 2011. Excluding the Texas
assets, LOE per BOE increased from $11.60 per BOE in the first quarter of 2010 to $13.52 per BOE in the first quarter of 2011.

Production and Property Taxes.Production and property taxes decreased $0.7 million (30%) to $1.5 million in the first
quarter of 2011
from $2.2 million in the first quarter of 2010. The decrease was primarily due to production and property taxes attributable to our Texas properties, which were sold in the second quarter of
2010. Excluding the Texas properties, production and property taxes were relatively consistent at $1.7 million in first quarter of 2010 and $1.5 million in the first quarter of 2011.

Transportation Expenses.Transportation expenses increased $0.9 million (84%) to $2.0 million in the first quarter of 2011
from
$1.1 million in the first quarter of 2010. On a per BOE basis, transportation expenses increased $0.62 per BOE, from $0.62 per BOE in the first quarter of 2010 to $1.24 per BOE in the first
quarter of 2011. The increase is primarily due to the contract described in"Other Revenues", related to the time-charter of a
double-hulled barge to transport oil produced from our South Ellwood field. Under that contract we pay a flat day rate, regardless of our usage of the barge, but have the ability to
sub-charter the vessel when not in use transporting production from the South Ellwood field (see "Other Revenues").

Depletion, Depreciation and Amortization (DD&A).DD&A expense increased $1.7 million (9%) to $21.7 million in the
first quarter of 2011
from $20.0 million in the first quarter of 2010. The increase is due to a higher depletion rate in the first quarter of 2011, which resulted from lower proved oil and

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natural
gas reserve volumes at the end of the first quarter of 2011 compared to proved oil and natural gas reserve volumes at the end of the first quarter of 2010. DD&A expense on a per unit basis
increased by $2.08 per BOE from $11.45 per BOE for the first quarter of 2010 to $13.53 per BOE for the first quarter of 2011.

Accretion of Abandonment Liability.Accretion expense remained constant at $1.6 million for both the first quarter of 2011 and the
first
quarter of 2010.

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

Three Months Ended
March 31,2010

2011Share-based compensation costs

$
1,640

$
2,280Other general and administrative costs


13,717


14,143General and administrative costs capitalized


(5,948
)

(6,594
)General and administrative expense

$
9,409

$
9,829


G&A
expenses were relatively consistent at $9.8 million in the first quarter of 2011 compared to $9.4 million in the first quarter of 2010. Excluding the effect of the
non-cash share-based compensation expense, G&A expense increased to $5.22 per BOE in the first quarter of 2011 from $4.77 per BOE in the first quarter of 2010, which was primarily due to
lower production in the first quarter of 2011 compared to the first quarter of 2010.

Interest Expense, Net.Interest expense, net of interest income, increased $2.6 million (25%) from $10.1 million in the first
quarter
of 2010 to $12.7 million in the first quarter of 2011. The increase was primarily the result the refinancing of our second lien term loan in February 2011 with the issuance of our 8.875% senior
notes. The interest rate on our second lien term loan, which was outstanding during the first quarter of 2010, averaged approximately 4.25% per annum during that period.

Amortization of Deferred Loan Costs.Amortization of deferred loan costs was $0.5 million in the first quarter of 2011 compared to
$0.7 million in the first quarter of 2010. The costs incurred relate to our loan agreements and are amortized over the estimated lives of the agreements.

Interest Rate Derivative (Gains) Losses, Net.In conjunction with the retirement of our second lien term loan in February 2011, we
settled our
outstanding interest rate swap contracts for $38.1 million. The result of settlement of the contracts and other activity in the first quarter of 2011 was an unrealized interest rate derivative
gain of $40.1 million and a realized interest rate derivative loss of $41.1 million. In the first quarter of 2010, we recognized an unrealized interest rate derivative loss of
$5.0 million and a realized interest rate derivative loss of $4.5 million.

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

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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 31,2010

2011Realized commodity derivative (gains) losses

$
(2,661
)
$
(5,468
)Amortization of commodity derivative premiums


5,657


1,990Unrealized commodity derivative (gains) losses for changes in fair value


(39,471
)

32,605Commodity derivative (gains) losses

$
(36,475
)
$
29,127


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 2011 and the same period in 2010 reflect the settlement of contracts at prices below the relevant strike prices. Unrealized commodity
derivative (gains) losses represent the change in the fair value of our open derivative contracts from period to period. Derivative premiums are amortized over the term of the underlying derivative
contracts.

Income Tax Expense (Benefit).We incurred losses before income taxes in 2008 and 2009. These losses were a key consideration that led us
to conclude
that we should maintain a full valuation allowance against our net deferred tax assets at December 31, 2010 and March 31, 2011 since we could not conclude that it is more likely than not
that the net deferred tax assets will be fully realized. As long as we continue to conclude that we have a need for a full valuation allowance against our net deferred tax assets, we likely will not
have any income tax expense or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims, or for state
income taxes. However, we continue to evaluate the existing evidence to determine the point at which we can conclude that it is more likely than not that we will be able to realize our net deferred
tax assets and, as a result, reverse the valuation allowance. The income tax benefit we recorded for the three months ended March 31, 2010, primarily relates to an increase in the estimated net
operating loss carryback claim for the 2003 through 2005 tax years. Due to our valuation allowance, there was no income tax expense (benefit) recorded during the three months ended March 31,
2011.

Net Income (Loss).Net loss for the first quarter of 2011 was $23.9 million compared to net income of $44.0 million for the
same period
in 2010. The change between periods is the result of the items discussed above.

Liquidity and Capital Resources

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

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Cash Flows

Three Months Ended
March 31,2010

2011(in thousands)Cash provided by operating activities

$
24,630

$
195Cash (used in) provided by investing activities


(45,347
)

(67,622
)Cash (used in) provided by financing activities


20,877


84,001


Net
cash provided by operating activities was $0.2 million in the first three months of 2011 compared with $24.6 million in the 2010 period. Cash flows from operating
activities in the first three months of 2011 as compared to the 2010 period were unfavorably impacted by the settlement of our interest rate derivative contracts in the first quarter of 2011 for
$38.1 million (see "Capital Resources and Requirements"). Additionally, decreased production and lower natural gas prices in the first quarter of 2011 compared to the first quarter
of 2010 contributed to the decrease. These decreases were partially offset by changes in our operating assets and liabilities.

Net
cash used in investing activities was $67.6 million in the first three months of 2011 compared with $45.3 million in the 2010 period. The primary investing activities
in the first three months of 2011 were $66.9 million in capital expenditures on oil and natural gas properties related to our capital expenditure program. The primary investing activities in
the first three months of 2010 were $42.9 million in capital expenditures on oil and natural gas properties related to our capital expenditure program.

Net
cash provided by financing activities was $84.0 million in the first three months of 2011 compared to $20.9 million during the 2010 period. The primary financing
activities in the first three months of 2011 were the two capital raising transactions we completed as described below in "Capital Resources and Requirements". The primary financing
activities in the first three months of 2010 were $20.0 million in net borrowings under our revolving credit facility to fund capital expenditures and working capital needs.

Capital Resources and Requirements

In the first quarter of 2011, we completed two capital raising transactions which provided us with additional liquidity. First, we
issued 4.6 million shares of common stock at a price to the public of $18.75 per share. We received net proceeds of approximately $82.2 million after deducting offering-related expenses.
Second, we issued $500 million of 8.875% senior unsecured notes which are due in February 2019. We received net proceeds of approximately $490.5 million from the notes offering, after
deducting offering-related expenses. The proceeds from the two transactions were used to repay the outstanding principal of $455.3 million and accrued interest of $1.6 million related to
our second lien term loan, settle the related interest rate swap contracts for $38.1 million and repay the outstanding balance of $45.0 million on our revolving credit facility.

We
plan to make substantial capital expenditures in the future for the acquisition, exploration, exploitation and development of oil and natural gas properties. We currently have a
budget for exploration, exploitation and development capital expenditures of $200 million in 2011, of which we incurred $64.3 million during the first quarter of 2011. As noted in
"OverviewCapital Expenditures," we expect to increase our 2011 budget modestly. We expect to fund our 2011 capital expenditures primarily with cash flow from operations, supplemented with
borrowings under our revolving credit facility and cash on hand. Additionally, we continue to pursue joint venture transactions related to our Monterey shale development project. We have significant
flexibility to reduce 2011 capital expenditures if warranted by business conditions or limits on our capital resources. Uncertainties relating to our capital resources and requirements in 2011 include
the possibility that one or more of the

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counterparties
to our hedging arrangements may fail to perform under the contracts, the effects of changes in commodity prices and differentials, results from our onshore Monterey shale program, which
could lead us to accelerate or decelerate activities depending on the extent of our success in developing the program, and the possibility that we will pursue one or more significant acquisitions that
would require additional debt or equity financing.

Amended Revolving Credit Facility.In April 2011, we entered into a fourth amended and restated credit agreement governing our revolving
credit
facility, which has a maturity date of March 31, 2016. The agreement contains customary representations, warranties, events of default, indemnities and covenants, including covenants that
restrict our ability to incur indebtedness and require us to maintain specified ratios of current assets to current liabilities and debt to EBITDA. The minimum ratio of current assets to current
liabilities (as those terms are defined in the agreement) is one to one; the maximum ratio of debt to EBITDA (as defined in the agreement) is four to one. While we do not expect to be in violation of
any of our debt covenants during 2011, we believe that it will be important to monitor the debt to EBITDA ratio requirement, especially if our EBITDA is less than we expect due to operational problems
or other factors, or if our borrowing needs are greater than we expect. The agreement requires us to reduce amounts outstanding under the facility with the proceeds of certain transactions or events,
including sales of assets, in certain circumstances. The revolving credit facility is secured by a first priority lien on substantially all of our assets.

Loans
under the revolving credit facility designated as "Base Rate Loans" bear interest at a floating rate equal to (i) the greater of (x) Bank of Montreal's announced base
rate, (y) the overnight federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.0%, plus (ii) an applicable margin ranging from 0.75% to 1.75%, based upon
utilization. Loans designated as "LIBO Rate Loans" under the revolving credit facility bear interest at (i) LIBOR plus (ii) an applicable margin ranging from 1.75% to 2.75%, based upon
utilization. A commitment fee of 0.5% per annum is payable with respect to unused borrowing availability under the facility.

The
revolving credit facility has a total capacity of $500.0 million, but is limited by a borrowing base which is currently established at $200.0 million. The borrowing
base is subject to redetermination twice
each year, and may be redetermined at other times at our request or at the request of the lenders. Lending commitments under the facility have been allocated at various percentages to a syndicate of
11 banks. Certain of the institutions included in the syndicate have received support from governmental agencies in connection with events in the credit markets. A failure of any members of the
syndicate to fund under the facility, or a reduction in the borrowing base, would adversely affect our liquidity. As described above, we repaid the outstanding principal balance on our revolving
credit facility in February 2011. As of May 4, 2011, there was no balance drawn on our revolving credit facility.

Second Lien Term Loan and 8.875% Senior Notes.We entered into a $500.0 million senior secured second lien term loan agreement in
May 2007.
Prior to repayment as described below, the term loan facility was secured by a second priority lien on substantially all of our assets and was due to mature on May 8, 2014. Loans under the
second lien term loan facility designated as "Base Rate Loans" bore interest at a floating rate equal to (i) the greater of the overnight federal funds rate plus 0.50% and the administrative
agent's announced base rate, plus (ii) 3.00%. Loans designated as "LIBO Rate Loans" bore interest at LIBOR plus 4.00%.

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

The
8.875% senior notes pay interest semi-annually in arrears on February 15 and August 15 of each year. We may redeem the notes prior to February 15,
2015 at a "make whole premium" defined in the indenture. Beginning February 15, 2015, we may redeem the notes at a redemption price of

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104.438%
of the principal amount and declining to 100% by February 15, 2017. The 8.875% senior notes are senior unsecured obligations and contain operational covenants that, among other things,
limit our ability to make investments, incur additional indebtedness or create liens on our assets.

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

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

Off-Balance Sheet Arrangements

At March 31, 2011, we had no existing off-balance sheet arrangements, as defined under SEC rules, that have or are
reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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Table of Contents

Item 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Derivative Transactions

Commodity Derivative Agreements.As of March 31, 2011, we had entered into various swap, collar and option agreements related to
our oil and
natural gas production. The aggregate economic effects of those agreements are summarized below. Location and quality differentials attributable to our properties are not included in the following
prices. The agreements provide for monthly settlement based on the differential between the agreement price and the actual NYMEX WTI (oil) or NYMEX Henry Hub (natural gas) price.

Oil
(NYMEX WTI)

Natural Gas
(NYMEX Henry Hub)Weighted Avg.
Barrels/day

Weighted Avg.
Prices per Bbl

Weighted Avg.
MMBtu/day

Weighted Avg.
Prices per MMBtuApril 1 - December 31, 2011:Swaps


2,400

$
105.65


24,000

$
4.44Collars(1)


5,000

$
50.00/$100.00




$
Puts(1)


2,000

$
50.00


36,000

$
5.92January 1 - December 31, 2012:Collars


8,500

$
75.29/$118.84




$
Puts




$



37,300

$
5.81January 1 - December 31, 2013:Collars


3,900

$
81.79/113.59


20,000

$
5.00/$7.02


---

We
have also entered into certain oil and natural gas basis swaps. The oil basis swaps fix the differential between the NYMEX WTI ("WTI") crude price index and the Inter-Continental
Exchange Brent crude price index ("Brent"). Historically the two price indexes have demonstrated a close correlation. The Southern California indexes on which we sell a significant percentage of our
oil have historically demonstrated a close correlation with these two major crude oil benchmarks. Recently, however, the relationship between WTI and Brent has diverged, favoring Brent crude, and the
Southern California indexes most relevant to us have continued to track their correlation to Brent

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prices.
The oil basis swaps we have entered into attempt to fix the current premium Southern California indexes are realizing relative to WTI and hedge the effect of future changes to the
WTI-Brent relationship. The natural gas basis swaps fix the differential between the Henry Hub price and the PG&E Citygate price, the index on which the majority of our natural gas is
sold. Our oil and natural gas basis swaps as of March 31, 2011 are presented below:

Oil Basis Swaps
(NYMEX WTI)

Natural Gas Basis Swaps
(NYMEX Henry Hub)Floating Index

Weighted Avg.
Bbls/Day

Weighted
Avg. Basis
Differential to
NYMEX WTI
(per Bbl)

Floating Index

Weighted Avg.
MMBtu/Day

Weighted
Avg. Basis
Differential to
NYMEX HH
(per MMBtu)Basis Swaps:April 1 - December 31, 2011

Brent Crude


3,700

$
9.30

PG&E Citygate


57,224

$
0.11January 1 - December 31, 2012

Brent Crude


7,630

$
6.90

PG&E Citygate


47,400

$
0.28January 1 - December 31, 2013

Brent Crude


3,900

$
5.88






$



Portfolio of Derivative Transactions

Our portfolio of commodity derivative transactions as of March 31, 2011 is summarized below:

Oil

Type of Contract

Counterparty

Basis

Quantity
(Bbl/d)

Strike Price
($/Bbl)

TermCollar

Key Bank

NYMEX


2,000

$50.00/$141.00


Apr 1 - Dec 31, 11Call Spread

Key Bank

NYMEX


2,000

$141.00/$100.00


Apr 1 - Dec 31, 11Collar

Credit Suisse

NYMEX


3,000

$50.00/$140.00


Apr 1 - Dec 31, 11Call Spread

Credit Suisse

NYMEX


3,000

$140.00/$100.00


Apr 1 - Dec 31, 11Put

Key Bank

NYMEX


2,000

$50.00


Apr 1 - Dec 31, 11Swap

Scotia Capital

NYMEX


2,400

$105.65


Apr 1 - Dec 31, 11Basis Swap

Bank of Montreal

NYMEX/Brent


3,700

$9.30


Apr 1 - Dec 31, 11Collar

RBS

NYMEX


3,000

$60.00/$121.10


Jan 1 - Dec 31, 12Collar

Bank of Montreal

NYMEX


1,500

$80.00/$110.85


Jan 1 - Dec 31, 12Collar

Bank of Montreal

NYMEX


1,000

$85.00/$120.30


Jan 1 - Dec 31, 12Collar

Scotia Capital

NYMEX


1,000

$85.00/$120.10


Jan 1 - Dec 31, 12Collar

BNP Paribas

NYMEX


2,000

$85.00/$120.10


Jan 1 - Dec 31, 12Basis Swap

Bank of Montreal

NYMEX/Brent


4,500

$7.28


Jan 1 - Mar 31, 12Basis Swap

Bank of Montreal

NYMEX/Brent


2,950

$7.28


Apr 1 - Dec 31, 12Basis Swap

Bank of Montreal

NYMEX/Brent


500

$7.15


Jan 1 - Mar 31, 12Basis Swap

Bank of Montreal

NYMEX/Brent


550

$7.15


Apr 1 - Dec 31, 12Basis Swap

Bank of Montreal

NYMEX/Brent


2,750

$6.90


Apr 1 - Dec 31, 12Basis Swap

Bank of Montreal

NYMEX/Brent


2,250

$6.05


Apr 1 - Dec 31, 12Collar

Credit Suisse

NYMEX


1,000

$80.00/$110.00


Jan 1 - Dec 31, 13Collar

Credit Suisse

NYMEX


500

$80.00/$110.00


Jan 1 - Dec 31, 13Collar

Credit Suisse

NYMEX


1,400

$85.00/$120.00


Jan 1 - Dec 31, 13Collar

BNP Paribas

NYMEX


1,000

$80.00/$110.00


Jan 1 - Dec 31, 13Basis Swap

Bank of Montreal

NYMEX/Brent


2,470

$6.05


Jan 1 - Dec 31, 13Basis Swap

Bank of Montreal

NYMEX/Brent


1,000

$5.80


Jan 1 - Dec 31, 13Basis Swap

Bank of Montreal

NYMEX/Brent


430

$5.10


Jan 1 - Dec 31, 13


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Table of Contents

Natural Gas

Type of Contract

Counterparty

Basis

Quantity
(MMBtu/d)

Strike Price
($/MMBtu)

TermCall (sold)

Credit Suisse

NYMEX


12,000

$
13.50


Apr 1 - Dec 31, 11Call (purchased)

RBS

NYMEX


12,000

$
13.50


Apr 1 - Dec 31, 11Collar

Bank of Montreal

NYMEX


24,000

$
5.75/$7.12


Apr 1 - Dec 31, 11Call (purchased)

Bank of Montreal

NYMEX


12,000

$
7.12


Apr 1 - Dec 31, 11Collar (sold put; purchased call)

Bank of Montreal

NYMEX


12,000

$
5.75/$7.12


Apr 1 - Dec 31, 11Put

Credit Suisse

NYMEX


10,000

$
6.00


Apr 1 - Dec 31, 11Put

Key Bank

NYMEX


14,000

$
6.00


Apr 1 - Dec 31, 11Swap

Scotia Capital

NYMEX


12,000

$
4.44


Apr 1 - Dec 31, 11Swap

Key Bank

NYMEX


12,000

$
4.4475


Apr 1 - Dec 31, 11Basis Swap

Credit Suisse

PG&E Citygate


12,000

$
0.03


Apr 1 - Dec 31, 11Basis Swap

Credit Suisse

PG&E Citygate


16,000

$
0.14


Apr 1 - Dec 31, 11Basis Swap

RBS

PG&E Citygate


11,000

$
0.04


Apr 1 - Dec 31, 11Basis Swap

Scotia Capital

PG&E Citygate


6,624

$
0.03


Apr 1 - Dec 31, 11Basis Swap

Scotia Capital

PG&E Citygate


11,600

$
0.27


Apr 1 - Dec 31, 11Collar

Credit Suisse

NYMEX


15,500

$
6.00/$9.10


Jan 1 - Dec 31, 12Call (purchased)

Credit Suisse

NYMEX


15,500

$
9.10


Jan 1 - Dec 31, 12Collar

Credit Suisse

NYMEX


14,000

$
5.50/$8.00


Jan 1 - Dec 31, 12Call (purchased)

Credit Suisse

NYMEX


14,000

$
8.00


Jan 1 - Dec 31, 12Put

RBS

NYMEX


7,800

$
6.00


Jan 1 - Dec 31, 12Basis Swap

Credit Suisse

PG&E Citygate


36,000

$
0.275


Jan 1 - Dec 31, 12Basis Swap

Key Bank

PG&E Citygate


11,400

$
0.275


Jan 1 - Dec 31, 12Collar

Credit Suisse

NYMEX


20,000

$
5.00/$7.02


Jan 1 - Dec 31, 13


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

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

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

We
have elected not to apply hedge accounting to any of our derivative transactions and consequently, we recognize mark-to-market gains and losses in earnings
currently, rather than deferring such amounts in accumulated other comprehensive income for those commodity derivatives that would qualify as cash flow hedges.

All
derivative instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying
market price at the determination date. Changes in the fair value of derivatives are recorded in commodity derivative (gains) losses on the consolidated statement of operations. As of March 31,
2011, the fair value of our commodity derivatives was a net asset of $0.4 million.

Interest Rate Derivative Transactions

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

See
notes to our condensed consolidated financial statements for a discussion of our long-term debt as of March 31, 2011.

Item 4.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of Timothy Marquez, our Chief Executive Officer, and Timothy Ficker, our Chief Financial
Officer, evaluated the effectiveness of our disclosure controls and procedures as of March 31, 2011. 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, 2011 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, 2010, which could materially affect our business, financial condition and/or future results. The risks
described in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial
also may materially adversely affect our business, financial condition and/or operating results.

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

Not Applicable

Item 3.    DEFAULTS UPON SENIOR SECURITIES

Not Applicable

Item 4.    REMOVED AND RESERVED

Not Applicable

Item 5.    OTHER INFORMATION

Not Applicable

Item 6.    EXHIBITS

Exhibit
Number

Exhibit10.6

Revised 2007 Long-Term Incentive Program.10.11

Employment Agreement, dated as of March 28, 2007, by and between Venoco, Inc. and Edward J. O'Donnell.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 5,
2011

VENOCO, INC.By:

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

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


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