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



Form 10-Q

ý

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the quarterly period ended September 30, 2009oro

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


Commission File Number: 333-123711

Venoco, Inc.

Delaware

77-0323555(State or other jurisdiction of
incorporation or organization)

(I.R.S. Employer
Identification Number)370 17th Street, Suite 3900
Denver, Colorado

80202-1370(Address of principal executive offices)

(Zip Code)


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

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

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

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

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

Large accelerated filer o

Accelerated filer ý

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

Smaller reporting company o


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

As of September 30, 2009, there were 52,464,837 shares of the issuer's common stock, par value $0.01 per share, issued and outstanding.



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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report on Form 10-Q contains "forward-looking statements" as that term is defined in the Private Securities
Litigation Reform Act of 1995. The use of any statements containing the words "anticipate," "intend," "believe," "estimate," "project," "expect," "plan," "should" or similar expressions are intended
to identify such statements. Forward-looking statements included in this report relate to, among other things, expected future production, expenses and cash flows in 2009 and 2010, the nature, timing
and results of capital expenditure projects, amounts of future capital expenditures, our future debt levels and liquidity, future compliance with covenants under our revolving credit facility, our
receipt of approvals relating to the South Ellwood full-field development project and the implementation and/or maintenance of delivery and sales arrangements relating to production from
the South Ellwood field. Although we believe that the expectations reflected in such forward-looking statements are reasonable, those expectations may prove to be incorrect. Disclosure of important
factors that could cause actual results to differ materially from our expectations, or cautionary statements, are included under the heading "Risk Factors" in this report and our Annual Report on
Form 10-K for the year ended December 31, 2008. Certain cautionary statements are also included elsewhere in this report, including, without limitation, in conjunction with
the forward-looking statements. All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our
behalf, are expressly qualified in their entirety by the cautionary statements. Except as required by law, we undertake no obligation to update any forward-looking statement. Factors that could cause
actual results to differ materially from our expectations include, among others, those factors referenced in the "Risk Factors" section of this report and our Annual Report on
Form 10-K for the year ended December 31, 2008 and such things as:



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Table of Contents

VENOCO, INC.
Form 10-Q for the Quarterly Period Ended September 30, 2009



TABLE OF CONTENTS



PART I.

FINANCIAL INFORMATIONItem 1.

Financial Statements (Unaudited)

2Condensed Consolidated Balance Sheets at December 31, 2008 and September 30, 2009

2Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2008 and the
Three and Nine Months Ended September 30, 2009

3Condensed Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2008 and
the Three and Nine Months Ended September 30, 2009

4Condensed Consolidated Statements of Changes in Stockholders' Equity for the Nine Months Ended September 30,
2009

5Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2008 and the Nine Months
Ended September 30, 2009

6Notes to Condensed Consolidated Financial Statements

7Item 2.

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

31Item 3.

Quantitative and Qualitative Disclosures about Market Risk

44Item 4.

Controls and Procedures

48PART II.

OTHER INFORMATIONItem 1.

Legal Proceedings

49Item 1A.

Risk Factors

49Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

49Item 3.

Defaults upon Senior Securities

49Item 4.

Submission of Matters to a Vote of Security Holders

49Item 5.

Other Information

49Item 6.

Exhibits

49Signatures

50


1

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PART IFINANCIAL INFORMATION



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

December 31,
2008

September 30,
2009ASSETSCURRENT ASSETS:Cash and cash equivalents

$
191

$
4,473Accounts receivable, net of allowance for doubtful accounts of $750 and $900 at December 31, 2008 and September 30, 2009, respectively


41,306


30,559Inventories


12,361


4,886Prepaid expenses and other current assets


4,314


4,730Income taxes receivable


546


5,462Commodity derivatives


57,247


29,017Total current assets


115,965


79,127PROPERTY, PLANT AND EQUIPMENT, AT COST:Oil and natural gas properties (full cost method, of which $30,228 and $28,968 for unproved properties were excluded from amortization at December 31,
2008 and September 30, 2009, respectively)


1,671,799


1,637,505Drilling equipment


14,460


14,460Other property and equipment


22,932


22,946Total property, plant and equipment


1,709,191


1,674,911Accumulated depletion, depreciation and amortization


(1,006,457
)

(1,070,335
)Net property, plant and equipment


702,734


604,576OTHER ASSETS:Commodity derivatives


35,314


22,227Deferred loan costs


7,458


5,531Other


2,783


3,708Total other assets


45,555


31,466TOTAL ASSETS

$
864,254

$
715,169LIABILITIES AND STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities

$
75,400

$
43,389Undistributed revenue payable


8,277


7,530Interest payable


5,325


4,844Current maturities of long-term debt


2,598


Commodity and interest derivatives


21,284


36,364Total current liabilities


112,884


92,127LONG-TERM DEBT


797,670


689,178COMMODITY AND INTEREST DERIVATIVES


9,363


15,673ASSET RETIREMENT OBLIGATIONS


79,504


87,195Total liabilities


999,421


884,173COMMITMENTS AND CONTINGENCIESSTOCKHOLDERS' EQUITY:Common stock, $.01 par value (200,000,000 shares authorized; 51,548,990 and 52,464,837 shares issued and outstanding at December 31, 2008 and
September 30, 2009, respectively)


515


525Additional paid-in capital


319,336


323,609Retained earnings (accumulated deficit)


(453,594
)

(493,138
)Accumulated other comprehensive loss


(1,424
)

Total stockholders' equity


(135,167
)

(169,004
)TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
864,254

$
715,169


See notes to condensed consolidated financial statements.

2

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

Three Months Ended
September 30,

Nine Months Ended
September 30,2008

2009

2008

2009REVENUES:Oil and natural gas sales

$
158,041

$
69,284

$
461,838

$
188,726Other


1,112


859


2,812


2,547Total revenues


159,153


70,143


464,650


191,273EXPENSES:Oil and natural gas production


42,418


28,015


107,565


80,280Transportation expense


1,655


1,144


4,334


2,954Depletion, depreciation and amortization


32,931


21,974


94,047


65,265Accretion of asset retirement obligations


1,044


1,429


3,065


4,174General and administrative, net of amounts capitalized


10,235


9,607


31,466


26,164Total expenses


88,283


62,169


240,477


178,837Income (loss) from operations


70,870


7,974


224,173


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


13,305


9,327


41,063


30,282Amortization of deferred loan costs


735


751


2,623


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


2,745


4,791


6,808


13,691Loss on extinguishment of debt











582Commodity derivative losses (gains), net


(303,052
)

7,577


136,367


9,501Total financing costs and other


(286,267
)

22,446


186,861


56,280Income (loss) before income taxes


357,137


(14,472
)

37,312


(43,844
)Income tax provision (benefit)


136,200


(9,200
)

14,400


(4,300
)Net income (loss)

$
220,937

$
(5,272
)
$
22,912

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

$
4.29

$
(0.10
)
$
0.45

$
(0.78
)Diluted

$
4.19

$
(0.10
)
$
0.44

$
(0.78
)Weighted average common shares outstanding:Basic


50,670


50,826


50,416


50,770Diluted


51,839


50,826


51,641


50,770


See
notes to condensed consolidated financial statements.

3

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

Three Months Ended
September 30,

Nine Months Ended
September 30,2008

2009

2008

2009Net income (loss)

$
220,937

$
(5,272
)
$
22,912

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


259


222


636


1,424Other comprehensive income (loss)


259


222


636


1,424Comprehensive income (loss)

$
221,196

$
(5,050
)
$
23,548

$
(38,120
)


See
notes to condensed consolidated financial statements.

4

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

Common Stock



Retained
Earnings
(Accumulated
Deficit)

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

Amount

TotalBALANCE AT DECEMBER 31, 2008


51,549

$
515

$
319,336

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








387





1,424


1,811Issuance of stock for cash upon exercise of options


20





173








173Issuance of restricted shares, net of cancellations


842


9


(9
)







Share-based compensation








3,450








3,450Issuance of common stock pursuant to Employee Stock Purchase Plan


54


1


257








258Disgorgement of stock sale profits








15








15Net income (loss)











(39,544
)




(39,544
)BALANCE AT SEPTEMBER 30, 2009


52,465

$
525

$
323,609

$
(493,138
)
$


$
(169,004
)


See
notes to condensed consolidated financial statements.

5

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

Nine Months Ended
September 30,2008

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

$
22,912

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


94,047


65,265Accretion of abandonment liability


3,065


4,174Deferred income taxes (benefit)


14,000


Share-based compensation


2,094


2,000Amortization of deferred loan costs


2,623


2,224Amortization of bond discounts and other non-cash interest


390


339Loss on extinguishment of debt





582Unrealized interest rate swap derivative losses (gains)


(287
)

(160
)Unrealized commodity derivative losses (gains) and amortization of premiums and other comprehensive loss


47,189


75,060Changes in operating assets and liabilities:Accounts receivable


(2,504
)

10,775Inventories


(814
)

(2,492
)Prepaid expenses and other current assets


(1,971
)

(380
)Income taxes receivable


400


(4,916
)Other assets


1,809


(925
)Accounts payable and accrued liabilities


3,390


(12,013
)Undistributed revenue payable


1,632


92Net premiums paid on derivative contracts


(13,840
)

(10,382
)Net cash provided by operating activities


174,135


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


(230,983
)

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


(10,021
)

(21,681
)Proceeds from sale of oil and natural gas properties





197,653Expenditures for other property and equipment


(3,591
)

(1,600
)Net cash (used in) provided by investing activities


(244,595
)

26,481CASH FLOWS FROM FINANCING ACTIVITIES:Proceeds from long-term debt


225,000


107,156Principal payments on long-term debt


(169,524
)

(219,167
)Payments for deferred loan costs


(828
)

(333
)Proceeds from derivative premium financing


7,817


Proceeds from Employee Stock Purchase Plan





258Proceeds from disgorgement of stock sale profits





15Proceeds from exercise of stock options


2,805


173Stock issuance costs


(5
)

Net cash (used in) provided by financing activities


65,265


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


(5,195
)

4,282Cash and cash equivalents, beginning of period


9,735


191Cash and cash equivalents, end of period

$
4,540

$
4,473Supplemental Disclosure of Cash Flow InformationCash paid for interest

$
38,534

$
30,460Cash paid for income taxes




$
616Supplemental Disclosure of Noncash ActivitiesAccrued capital expenditures at period end

$
19,993

$
11,224Increase (decrease) in accrued capital expenditures

$
(22,687
)
$
(18,979
)


See notes to condensed consolidated financial statements.

6

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

1. SIGNIFICANT ACCOUNTING POLICIES

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

Basis of PresentationThe unaudited condensed consolidated financial statements include the accounts of Venoco and its subsidiaries, all of which
are
wholly owned. The financial statements have been prepared in accordance with U.S. generally accepted accounting principles for interim financial reporting. All significant intercompany balances and
transactions have been eliminated in consolidation. In the opinion of management, all material adjustments considered necessary for a fair presentation of the Company's interim results have been
reflected. The Company has evaluated subsequent events and transactions through November 2, 2009, which is the date these financial statements were issued, 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, 2008 includes certain definitions and a summary of significant accounting policies and should
be read in conjunction with this report. The results for interim periods are not necessarily indicative of annual results.

In
the course of preparing the condensed consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets,
liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the
occurrence of future events and, accordingly, actual results could differ from amounts initially established. Significant areas requiring the use of assumptions, judgments and estimates include
(1) oil and gas reserves; (2) cash flow estimates used in ceiling tests of oil and natural gas properties; (3) depreciation, depletion and amortization; (4) asset
retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation
of commodity and interest 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 that the specific transaction occurs. At
December 31, 2008 and September 30, 2009, the Company has recorded a valuation allowance against its net deferred tax assets since it cannot conclude that it is more likely than not that
the deferred tax assets will be fully realized on future tax returns. For the nine months ended September 30, 2009, the net tax benefit recorded by the Company relates to a reduction of prior
year current income tax expense ($6.6 million benefit), partially offset by federal AMT (primarily related to the Hastings transaction) and state income tax expense of $2.3 million.

Earnings Per ShareBasic earnings (loss) per share is calculated by dividing net income by the weighted average number of shares outstanding for
the
period. Under the treasury stock method, diluted earnings per share is calculated by dividing net income 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.

7

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

Effective
January 1, 2009, 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. In periods of net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company
losses. The two-class method has been applied to the three and nine month periods ended September 30, 2008 and 2009. Application of the two-class method resulted in
lower reported basic and diluted earnings per share for the three month period ended September 30, 2008. Application of the two-class method to the nine month period ended September 30,
2008 did not change the reported basic or diluted earnings per share. Because the Company incurred net losses for the three and nine month periods ended September 30, 2009, application of the
two-class method did not have an impact on the earnings per share calculation.

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

Three Months Ended
September 30,

Nine Months Ended
September 30,2008

2009

2008

2009Dilutive


3,992,100





4,066,665


Anti-dilutive


547,803


5,054,465


607,782


4,917,284


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

Three Months Ended
September 30,

Nine Months Ended
September 30,2008

2009

2008

2009Net income (loss)

$
220,937

$
(5,272
)
$
22,912

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


3,670





324


Net income (loss) allocated to common stock

$
217,267

$
(5,272
)
$
22,588

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


50,670


50,826


50,416


50,770Add: dilutive effect of stock options and non-vested restricted stock


1,169





1,225


Diluted weighted average common shares outstanding


51,839


50,826


51,641


50,770Basic earnings per common share

$
4.29

$
(0.10
)
$
0.45

$
(0.78
)Diluted earnings per common share

$
4.19

$
(0.10
)
$
0.44

$
(0.78
)


8

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)



In December 2008, the Securities and Exchange Commission ("SEC") published revised rules regarding oil and gas reserves reporting
requirements. The objective of the rules is to provide readers of financial statements with more meaningful and comprehensive understanding of oil and gas reserves. Key elements of the revised rules
include a change in the pricing used to estimate reserves at period end, changes in certain definitions, optional disclosure of probable and possible reserves, allowance of the use of new technologies
in the determination of reserves and additional disclosure requirements. The rules also revise the prices used for reserves in determining depletion and the full cost ceiling test from a period end
price to a 12-month average price. The revised rules are effective for annual reports for fiscal years ending on or after December 31, 2009. Early adoption is not allowed.
Additionally, in September 2009, the Financial Accounting Standards Board ("FASB") issued an exposure draft regarding updates to existing guidance to align the oil and gas reserve estimation and
disclosure requirements with the SEC's revised oil and gas reserves reporting rules discussed above. The proposed updates are expected to be effective for fiscal years ending on or after
December 31, 2009, however, final guidance has not yet been issued. The Company is currently assessing the impact that the adoption of both the SEC rules and the FASB proposed guidance will
have on its operating results, financial position, cash flows, oil and natural gas reserves and disclosures.

2. ACQUISITIONS AND SALES OF PROPERTIES

Sacramento Basin Asset Acquisition.In February 2009, the Company entered into a purchase and sale agreement pursuant to which it agreed
to buy
certain natural gas producing properties in the Sacramento Basin from Aspen Exploration Corporation and certain other parties. The properties acquired are in close proximity to the Company's existing
operations in the Sacramento Basin and, therefore, complement the Company's current natural gas portfolio. The transaction closed on June 30, 2009, with an effective date of December 1,
2008. The purchase price of $21.4 million consisted of cash paid of $21.3 million and certain payables related to the properties acquired of $0.1 million assumed by the Company.

The
Sacramento Basin asset acquisition qualifies as a business combination, and therefore, the Company was required to estimate the fair value of the assets acquired and liabilities
assumed as of the acquisition date (June 30, 2009) in order to record the acquisition. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability
in an orderly transaction between market participants at the measurement date.

The
fair value of the acquired properties was determined based upon numerous inputs, many of which were unobservable (which are defined as Level 3 inputs). The significant inputs
used in estimating the fair value were: (1) NYMEX natural gas futures prices at June 30, 2009 (observable), (2) projections of the estimated quantities of natural gas reserves,
(3) projections regarding rates and timing of production, (4) projections regarding amounts and timing of future development and abandonment costs, (5) projections regarding the
amounts and timing of operating costs and property taxes, (6) estimated risk adjusted discount rates and (7) estimated inflation rates. As a result of applying the above assumptions, the
Company estimated the aggregate fair value of the acquisition at $21.4 million. The estimated fair value of the acquisition was assigned to the assets acquired and liabilities assumed as
follows: $22.9 million to proved properties, $1.5 million to unevaluated properties,

9

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

2. ACQUISITIONS AND SALES OF PROPERTIES (Continued)

$1.1 million
to operating equipment and $4.1 million to asset retirement obligation. Because the estimated fair value and purchase price were equivalent, the Company did not record
goodwill or a gain related to the acquisition.

Hastings Complex Sale.In February 2009, the Company closed the sale of its principal interests in the Hastings complex ("Hastings
Sale") to a
subsidiary of Denbury Resources Inc. ("Denbury") for approximately $197.7 million. The Company used the proceeds from the sale to repay fully the then outstanding balance of the
revolving credit facility of $187.1 million and related interest of $0.5 million. In addition, the Company paid $5.5 million toward the principal balance on the second lien term
loan. The Company did not recognize a gain for financial reporting purposes, but applied the proceeds from the Hastings Sale to reduce the capitalized cost of its oil and natural gas properties.

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

3. LONG-TERM DEBT

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

December 31,
2008

September 30,
2009Revolving credit agreement

$
135,052

$
45,000Second lien term loan


500,000


494,4858.75% senior notes


149,590


149,693Financed derivative premiums


15,626


Total long-term debt


800,268


689,178Less: current portion of long-term debt


(2,598
)

Long-term debt, net of current portion

$
797,670

$
689,178


Revolving credit facility.The Company has a $300.0 million revolving credit facility with a syndicate of banks ("revolving credit
facility"),
with a maturity date of March 30, 2011. The borrowing base under the facility is subject to redetermination twice each year, and may be redetermined at other times at our request or at the
request of the lenders. The facility is secured by a first priority lien on substantially all of the Company's oil and natural gas properties and other assets, including the equity interests in all of
the Company's subsidiaries, and is unconditionally guaranteed by each of the Company's operating subsidiaries other than Ellwood Pipeline, Inc. The collateral also secures the Company's
obligations to hedging counterparties that are also lenders, or affiliates of lenders, under the facility. Loans designated as Base Rate Loans under the facility bear interest at a floating rate equal
to (i) the greater of (x) the Bank of Montreal's announced base rate, (y) the overnight federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.5%,
plus (ii) an applicable margin ranging

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(UNAUDITED)

3. LONG-TERM DEBT (Continued)

from
0.75% to 1.50%, based upon utilization. Loans designated as LIBO Rate Loans under the facility bear interest at (i) LIBOR plus (ii) an applicable margin ranging from 2.25% to 3.00%,
based upon utilization. A commitment fee of 0.50% per annum is payable with respect to unused borrowing availability under the facility. The agreement governing the facility contains customary
representations, warranties, events of default, indemnities and covenants, including operational covenants that restrict the Company's ability to incur indebtedness and financial covenants that
require the Company to maintain specified ratios of current assets to current liabilities and debt to EBITDA.

The
borrowing base under the revolving credit facility has been allocated at various percentages to a syndicate of 12 banks. Certain of the institutions included in the syndicate have
received support from governmental agencies in connection with recent events in the credit markets. In addition, 4.75% of the $125.0 million borrowing base has been allocated to Lehman
Commercial Paper, Inc. ("LCP"), a wholly-owned subsidiary of Lehman Brothers Holdings, Inc., which filed for bankruptcy protection in September 2008. LCP is no longer funding its portion
of the Company's borrowing requests made under the facility. As of November 2, 2009, the Company had effective available borrowing capacity of $61.6 million under the facility, net of
the outstanding balance of $54.3 million, $3.2 million in outstanding letters of credit and $5.9 million attributable to LCP.

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

The
term loan agreement contains customary representations, warranties, events of default and indemnities and certain customary covenants, including covenants that restrict the Company's
ability to
incur additional indebtedness. The facility is secured by second priority liens on substantially all of the Company's oil and natural gas properties and other assets, including the equity interests in
all of its subsidiaries, and is unconditionally guaranteed by each of the Company's subsidiaries other than Ellwood Pipeline, Inc. Under the terms of the second lien term loan agreement, if the
8.75% senior notes were outstanding on September 20, 2011, the principal on the facility would be due on that date. However, as a result of the Company's refinancing of the 8.75% senior notes
described below, the maturity date of the principal on the second lien term loan will be extended to May 8, 2014.

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

Senior notes.In December 2004, the Company issued $150.0 million in 8.75% senior notes due December 2011. Prior to the
satisfaction and
discharge of the 8.75% senior notes described below, interest was due each June 15 and December 15. The 8.75% notes were senior obligations and contained covenants that, among other
things, limited the Company's ability to make investments, incur additional debt, issue preferred stock, pay dividends, repurchase its stock, create liens or sell assets.

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(UNAUDITED)

3. LONG-TERM DEBT (Continued)

The
8.75% senior notes were issued as unsecured obligations, but were subsequently secured equally and ratably with the Company's second lien term loan facility.

In
October 2009, the Company issued $150.0 million in 11.50% senior notes due October 2017 at a price of 95.03% of par. The 11.50% senior notes are senior unsecured obligations
and contain covenants similar to the existing senior notes. Concurrently with the sale of the 11.50% senior notes, the Company irrevocably deposited $159.8 million in cash with the trustee
under the indenture governing the 8.75% senior notes, thus effecting a satisfaction and discharge of the 8.75% senior notes. Additionally, the Company issued an irrevocable notice of redemption to
call the 8.75% senior notes for redemption at 102.188% on December 15, 2009. The funds deposited with the trustee, comprised of net proceeds of the offering of $141.0 million,
$14.3 million of additional borrowings under the Company's revolving credit facility and $4.5 million of cash on hand, are sufficient to pay the aggregate redemption price and all
accrued interest on the 8.75% senior notes as of the redemption date. As a result of the refinancing of the 8.75% senior notes, the maturity of the second lien term loan will be extended from
September 20, 2011 to May 8, 2014 under the terms of the second lien term loan agreement.

The
Company was in compliance with all debt covenants at September 30, 2009.

Financed Derivative Premiums.The Company previously entered into derivative contracts that contain provisions for the deferral of the
payment or
receipt of premiums until the period of production for which the derivative contract relates. Both the derivative and the net liability for the payment of premiums were recorded at their fair values
at the inception of the derivative contracts. The Company paid the balance of all outstanding financed derivative premiums during the second quarter of 2009. The Company recognized a loss on
extinguishment of debt of $0.6 million in connection with the settlement of the financed derivative premiums.

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS

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

The
use of derivatives also involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company's derivative contracts
are with multiple counterparties to minimize exposure to any individual counterparty. The Company generally 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

default
by one of the parties to the agreement. All of the counterparties to the Company's derivative contracts are also lenders, or affiliates of lenders, under its revolving credit facility.
Therefore, the Company is not required to post collateral when the Company is in a derivative liability position. The Company's revolving credit facility and derivative contracts contain provisions
that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations.

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

Because
a large portion of the Company's commodity derivatives do not qualify for hedge accounting and to increase clarity in its financial statements, the Company elected to discontinue
hedge accounting prospectively for its commodity derivatives beginning April 1, 2007. Consequently, from that date forward, the Company has recognized mark-to-market
gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (loss) for those commodity derivatives that qualify as cash flow hedges. As of
September 30, 2009, the remaining unrealized derivative fair value loss of $0.5 million ($0.0 million after tax) for derivative contracts previously designated as cash flow hedges
is recorded in accumulated other comprehensive loss. The Company will amortize the remaining net unrealized derivative losses out of accumulated other comprehensive loss into earnings during the next
three months.

The
Company has paid premiums related to certain of its outstanding derivative contracts. These premiums are amortized over the period for which the contracts are effective. At
September 30, 2009, the balance of unamortized derivative premiums was $35.9 million, of which $6.0 million, $13.2 million, $13.0 million and $3.7 million
will be amortized in 2009 (remaining three months), 2010, 2011 and 2012, respectively.

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

Three Months Ended
September 30,

Nine Months Ended
September 30,2008

2009

2008

2009Realized commodity derivative (gains) losses

$
34,095

$
(16,675
)
$
90,214

$
(63,748
)Amortization of commodity derivative premiums


1,626


5,999


5,155


16,662Unrealized commodity derivative (gains) losses for changes in fair value:


(338,773
)

18,253


40,998


56,587Commodity derivative (gains) losses

$
(303,052
)
$
7,577

$
136,367

$
9,501


Crude Oil Agreements.As of September 30, 2009, the Company had entered into option, swap and collar agreements to receive average
minimum and
maximum New York Mercantile Exchange

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

(NYMEX)
West Texas Intermediate (WTI) prices as summarized below. Location and quality differentials attributable to the Company's properties are not included in the following prices. The agreements
provide for monthly settlement based on the differential between the agreement price and the actual NYMEX crude oil price.

MinimumMaximumAvg. PricesBarrels/day

Barrels/day

Avg. PricesCrude oil derivatives at September 30, 2009 for production:October 1 - December 31, 2009


8,750

$
56.41


6,750

$
63.80January 1 - December 31, 2010


8,000

$
56.22


6,150

$
72.88January 1 - December 31, 2011


7,000

$
50.00


7,000

$
141.64


Natural Gas Agreements.As of September 30, 2009, the Company had entered into option, swap and collar agreements to receive
average minimum
and maximum NYMEX or PG&E Citygate prices as follows:

Minimum

MaximumMMBtu/Day

Avg. Prices

MMBtu/Day

Avg. PricesNatural gas derivatives at September 30, 2009 for production:October 1 - December 31, 2009


61,125

$
7.02


23,125

$
11.39January 1 - December 31, 2010


58,900

$
6.48


27,900

$
9.26January 1 - December 31, 2011


36,000

$
6.59


12,000

$
13.77January 1 - December 31, 2012


23,300

$
6.00


15,500

$
9.10


In
October 2009, the Company entered into a series of transactions whereby it reduced the ceilings on existing natural gas contracts covering 27,900 MMbtu per day from an average of
$9.00 to $7.00 for the period from January 2010 through December 2010 and on 12,000 MMBtu per day from $13.50 to $10.00 for the period from January 2011 through December 2011. The Company utilized the
proceeds from these transactions to partially fund the purchase of oil call spreads that increase the ceilings on existing oil contracts covering 3,500 Bbls per day from $73.00 to $85.00 and on 1,000
Bbls per day from $72.80 to $95.00, each for the period from January 2010 to December 2010.

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 June 2010. The Company paid a fixed interest rate of 5.32% and received a floating interest rate based on the three-month LIBO rate, with settlements made quarterly.
In June 2009, the Company entered into a series of transactions to extend the term of the interest rate swap to September 2011 and reduce the rate from 5.32% to 4.035%. Under the revised terms, the
Company received a floating interest rate based on the one-month LIBO rate, with settlements made monthly. As a result of the swap, $500 million of the Company's variable rate debt
was to effectively bear interest at a fixed rate of approximately 8.0% until September 2011. The Company did not designate the interest rate swap as a hedge.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

In connection with the extension of the maturity of the Company's second lien term loan facility to
May 2014, the Company entered into a revised interest rate swap agreement in October 2009 to extend the terms of the existing interest rate swap agreement from September 2011 to May 2014 and reduced
the rate from 4.035% to a weighted average rate of 3.840%. As a result of the revised agreement, $500 million of the Company's variable rate debt will effectively bear interest at a fixed rate
of approximately 7.8%. The Company did not designate the interest rate swap as a hedge.

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

Three Months ended
September 30,

Nine Months ended
September 30,2008

2009

2008

2009Realized interest rate derivative (gains) losses

$
3,371

$
4,781

$
7,095

$
13,851Unrealized interest rate derivative (gains) losses


(626
)

10


(287
)

(160
)Interest rate derivative (gains) losses, net

$
2,745

$
4,791

$
6,808

$
13,691


The
estimated fair values of derivatives included in the consolidated balance sheets at December 31, 2008 and September 30, 2009 are summarized below. The
net fair value of the Company's derivatives decreased by $62.7 million from a net asset of $61.9 million at December 31, 2008 to a net liability of $0.8 million at
September 30, 2009 due to higher futures prices for oil and natural gas prices, which are used in the calculation of the fair value of commodity derivatives. The Company does not offset asset
and liability positions with the same counterparties within the financial statements, rather, all contracts are presented at their gross estimated fair value. As of the dates indicated, the Company's
derivative assets and liabilities are presented below (in thousands). These balances represent the estimated fair value of the contracts. The Company has not designated any of

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

the
contracts as hedging instruments. The main headings represent the balance sheet captions for the contracts presented.

December 31,
2008

September 30,
2009Current AssetsCommodity derivatives:Oil derivative contracts

$
23,970

$
474Gas derivative contracts


33,277


28,54357,247


29,017Other AssetsCommodity derivatives:Oil derivative contracts


11,660


3,740Gas derivative contracts


23,654


18,48735,314


22,227Current LiabilitiesCommodity and interest derivatives:Oil derivative contracts


(1,672
)

(14,842
)Gas derivative contracts


(652
)

(4,202
)Interest rate derivative contracts


(18,960
)

(17,320
)(21,284
)

(36,364
)Commodity and interest rate derivatives:Oil derivative contracts





(3,183
)Gas derivative contracts


(180
)

(1,827
)Interest rate derivative contracts


(9,183
)

(10,663
)(9,363
)

(15,673
)Net derivative asset (liability)

$
61,914

$
(793
)


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. Level 1 primarily consists of financial instruments such as exchange-traded
derivatives and listed equities.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

5. FAIR VALUE MEASUREMENTS (Continued)

Level 2Pricing
inputs are other than quoted prices in active markets included in level 1, but are either directly or indirectly observable as of the reported
date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various
assumptions, including quoted forward prices for interest rates and commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as
other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are
supported by observable levels at which transactions are executed in the marketplace. Instruments in this category generally include non-exchange-traded derivatives such as commodity
swaps, interest rate swaps, options and collars.

Level 3Pricing
inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed
methodologies that result in management's best estimate of fair value. Instruments in this category generally include non-exchange-traded derivatives such as commodity swaps, options and
collars that are valued similar to the industry-standard models described above, however, these derivatives are classified in Level 3 because of inputs that may not be observable.

Financial
assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the
significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value
hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of
September 30, 2009 (in thousands).

Level 1

Level 2

Level 3

Fair Value
as of
September 30,
2009Assets (Liabilities):Commodity derivatives

$


$
51,244

$


$
51,244Commodity derivatives





(24,054
)




(24,054
)Interest rate swaps





(27,983
)




(27,983
)


Fair Value of Financial InstrumentsThe 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 values

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

5. FAIR VALUE MEASUREMENTS (Continued)

of
the second lien term loan and the 8.75% senior notes were derived from available market data. This disclosure does not impact our financial position, results of operations or cash flows.

September 30, 2009Long Term Debt (in thousands)

Carrying
Amount

Estimated
Fair ValueSecond lien term loan

$
494,485

$
420,3128.75% senior notes

$
149,693

$
150,750


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 (level 3 inputs), 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.

The
following table summarizes the activities for the Company's asset retirement obligations for the nine months ended September 30, 2008 and 2009 (in thousands):

Nine Months
Ended
September 30, 2008

Nine Months
Ended
September 30, 2009Asset retirement obligations at beginning of period

$
52,220

$
80,579Revisions of estimated liabilities


582


332Liabilities incurred/acquired


2,767


6,742Liabilities settled


(286
)

(564
)Disposition of properties





(2,993
)Accretion expense


3,065


4,174Asset retirement obligations at end of period


58,348


88,270Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)


(500
)

(1,075
)Long-term asset retirement obligations

$
57,848

$
87,195


7. CAPITAL STOCK

The Company has 61.3 million shares of common stock issued or reserved for issuance at September 30, 2009. At September 30, 2009, the Company has 52.5 million
common shares issued and

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

7. CAPITAL STOCK (Continued)

outstanding,
of which 1.6 million shares are restricted stock granted under the Company's 2005 stock incentive plan. At September 30, 2009, the Company had approximately
3.3 million options outstanding and 5.2 million shares available to be issued pursuant to awards under its stock incentive plans, including the 2008 Employee Stock Purchase Plan.

8. SHARE-BASED PAYMENTS

The Company has granted options to directors, certain employees and officers of the Company other than its CEO, under its 2000 and 2005 Stock Plans (the "Stock Plans"). As of
September 30, 2009, there are a total of 3,348,463 options outstanding with a weighted average exercise price of $8.95 ($6.00 to $20.00). The options vest over a four year period, with 20%
vesting on the grant date and 20% vesting on each subsequent anniversary of the grant date. The options typically have a maximum life of 10 years. The options will generally vest upon a change
in control of the Company. Unexercised options expire when an option holder elects to terminate employment or if the Company terminates the holder's employment for misconduct. If the Company
terminates a holder's employment other than for misconduct, unvested options generally terminate and the holder has a limited period of time within which to exercise vested options, unless the award
agreement provides otherwise.

Effective
February 1, 2009, the Company implemented a non-compensatory 2008 Employee Stock Purchase Plan (the "ESPP"), which has been approved by the Company's Board
of Directors and shareholders. In connection with the approval of the ESPP, the Board authorized 1.5 million shares of common stock to be issued under the ESPP. Participation in the ESPP is
open to all employees, other than executive officers, who meet limited qualifications. Under the terms of the ESPP, employees are able to purchase Company stock at a 5% discount as determined by the
fair market value of the Company's stock on the last trading day of each purchase period. Individual employees are limited to $25,000 of common stock purchased in any calendar year.

As
of September 30, 2009, there were a total of 1,607,521 shares of restricted stock outstanding under the Company's 2005 stock incentive plan, including 632,737 shares granted to
its CEO. The restricted shares generally have a requisite service period of four years. The grant date fair value of restricted stock, subject to service conditions only, is determined by the
Company's closing stock price on the day prior to the date of grant. The vesting of 943,291 shares is also subject to market conditions based on the Company's total shareholder return in comparison to
peer group companies for each calendar year. The weighted-average fair value of the restricted shares subject to market conditions was derived using a Monte Carlo technique and the fair value of
awards granted was estimated to be $2.61 per share in 2009. As of September 30, 2009, none of the restricted shares subject to market conditions have vested. The estimated grant date fair
values of restricted share awards are recognized as expense over the requisite service periods.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

8. SHARE-BASED PAYMENTS (Continued)

The
following summarizes the Company's stock option activity for the nine months ended September 30, 2009:

Options

Weighted
Average
Exercise
PriceOutstanding, start of period


3,504,263

$
9.16Granted





Exercised


(20,000
)
$
8.67Cancelled


(135,800
)
$
11.36Outstanding, end of period


3,348,463

$
8.95Exercisable, end of period


3,105,963

$
8.34


The
following summarizes the Company's unvested restricted stock award activity for the nine months ended September 30, 2009:

Shares

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


851,545

$
12.65Granted


891,376

$
2.88Vested


(86,286
)
$
14.16Forfeited


(49,114
)
$
11.28Non-vested, end of period


1,607,521

$
7.20


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

Three Months Ended
September 30,

Nine Months Ended
September 30,2008

2009

2008

2009General and administrative expense

$
1,140

$
910

$
3,400

$
2,940Oil and natural gas production expense


160


190


420


510Total share-based compensation costs


1,300


1,100


3,820


3,450Less: share-based compensation costs capitalized


(590
)

(294
)

(1,726
)

(1,450
)Share-based compensation expensed

$
710

$
806

$
2,094

$
2,000


As
of September 30, 2009, there was $1.0 million of total unrecognized compensation cost related to stock options which is expected to be amortized over a weighted-average
period of 1.3 years and $6.8 million of total unrecognized compensation cost related to restricted stock which is expected to be amortized over a weighted-average period of
2.5 years.

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(UNAUDITED)

9. LITIGATION



Between June 2003 and April 2005, six lawsuits were filed against the Company and certain other energy companies in Los Angeles County
Superior Court by persons who attended Beverly Hills High School or who were or are citizens of Beverly Hills/Century City or visitors to that area during the time period running from the 1930s to
date. There are approximately 1,000 plaintiffs (including plaintiffs in two related lawsuits in which the Company has not been named) who claimed to be suffering from various forms of cancer or other
illnesses, fear they may suffer from such maladies in the future, or are related to persons who have suffered from cancer or other illnesses. Plaintiffs alleged that exposure to substances in the air,
soil and water that originated from either oil-field or other operations in the area were the cause of the cancers and other maladies. The Company has owned an oil and natural gas facility
adjacent to the school since 1995. For the majority of the plaintiffs, their alleged exposures occurred before the Company acquired the facility. All cases were consolidated before one judge. Twelve
"representative" plaintiffs were selected to have their cases tried first, while all of the other plaintiffs' cases were stayed. In November 2006, the
judge entered summary judgment in favor of all defendants in the test cases, including the Company. The judge dismissed all claims by the test case plaintiffs on the ground that they offered no
evidence of medical causation between the alleged emissions and the plaintiffs' alleged injuries. Plaintiffs appealed the ruling. A decision on the appeal is expected in 2010. The Company vigorously
defended the actions, and will continue to do so until they are resolved. Certain defendants have made claims for indemnity for events occurring prior to 1995, which the Company is disputing. The
Company cannot predict the cost of these indemnity claims at the present time.

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

The
Company has not accrued for a loss contingency relating to the Beverly Hills litigation because the Company believes that, although unfavorable outcomes in the proceedings may be
reasonably possible, the Company does not consider them to be probable or reasonably estimable. If one or more of these matters are resolved in a manner adverse to the Company, and if insurance

21

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

9. LITIGATION (Continued)

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

10. GUARANTOR FINANCIAL INFORMATION

All subsidiaries of the Company other than Ellwood Pipeline Inc. ("Guarantors") fully and unconditionally guaranteed, on a joint and several basis, the Company's obligations under
the 8.75% senior notes. Ellwood Pipeline, Inc. is not a Guarantor (the "Non-Guarantor Subsidiary"). The condensed consolidating financial information for prior periods has been
revised to reflect the guarantor and non-guarantor status of the Company's subsidiaries as of September 30, 2009. All Guarantors are 100% owned by the Company. Presented below are
the Company's condensed consolidating balance sheets, statements of operations and statements of cash flows as required by Rule 3-10 of Regulation S-X of the
Securities Exchange Act of 1934.

22

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedASSETSCURRENT ASSETS:Cash and cash equivalents

$
190

$
1

$


$


$
191Accounts receivable


33,654


7,652








41,306Inventories


5,544


6,817








12,361Prepaid expenses and other current assets


4,314











4,314Income taxes receivable


546











546Commodity derivatives


57,247











57,247TOTAL CURRENT ASSETS


101,495


14,470








115,965PROPERTY, PLANT & EQUIPMENT, NET


580,317


121,353


1,064





702,734COMMODITY DERIVATIVES


35,314











35,314INVESTMENTS IN AFFILIATES


498,670








(498,670
)

OTHER


9,546


695








10,241TOTAL ASSETS

$
1,225,342

$
136,518

$
1,064

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

$
67,832

$
7,568

$


$


$
75,400Undistributed revenue payable


8,277











8,277Interest payable


5,325











5,325Current maturities of long-term debt


2,598











2,598Commodity and interest derivatives


21,284











21,284TOTAL CURRENT LIABILITIES:


105,316


7,568








112,884LONG-TERM DEBT


797,670











797,670COMMODITY AND INTEREST DERIVATIVES


9,363











9,363ASSET RETIREMENT OBLIGATIONS


68,678


10,107


719





79,504INTERCOMPANY PAYABLES (RECEIVABLES)


379,482


(336,243
)

(43,239
)




TOTAL LIABILITIES


1,360,509


(318,568
)

(42,520
)




999,421TOTAL STOCKHOLDERS' EQUITY


(135,167
)

455,086


43,584


(498,670
)

(135,167
)TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
1,225,342

$
136,518

$
1,064

$
(498,670
)
$
864,254


23

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS  AT SEPTEMBER 30, 2009 (Unaudited)  (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedASSETSCURRENT ASSETS:Cash and cash equivalents

$
4,472

$
1

$


$


$
4,473Accounts receivable


25,762


4,723


74





30,559Inventories


4,682


204








4,886Prepaid expenses and other current assets


4,730











4,730Income tax receivable


5,462











5,462Commodity derivatives


29,017











29,017TOTAL CURRENT ASSETS


74,125


4,928


74





79,127PROPERTY, PLANT & EQUIPMENT, NET


677,906


(75,756
)

2,426





604,576COMMODITY DERIVATIVES


22,227











22,227INVESTMENTS IN AFFILIATES


508,289








(508,289
)

OTHER


8,895


344








9,239TOTAL ASSETS

$
1,291,442

$
(70,484
)
$
2,500

$
(508,289
)
$
715,169LIABILITIES AND STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities

$
36,746

$
6,643

$


$


$
43,389Undistributed revenue payable


7,530











7,530Interest payable


4,844











4,844Commodity and interest derivatives


36,364











36,364TOTAL CURRENT LIABILITIES:


85,484


6,643








92,127LONG-TERM DEBT


689,178











689,178COMMODITY AND INTEREST DERIVATIVES


15,673











15,673ASSET RETIREMENT OBLIGATIONS


78,937


7,499


759





87,195INTERCOMPANY PAYABLES (RECEIVABLES)


591,174


(544,408
)

(46,766
)




TOTAL LIABILITIES


1,460,446


(530,266
)

(46,007
)




884,173TOTAL STOCKHOLDERS' EQUITY


(169,004
)

459,782


48,507


(508,289
)

(169,004
)TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
1,291,442

$
(70,484
)
$
2,500

$
(508,289
)
$
715,169


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 SEPTEMBER 30, 2008 (Unaudited)  (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
116,852

$
41,189

$


$


$
158,041Other


1,037


(14
)

1,548


(1,459
)

1,112Total revenues


117,889


41,175


1,548


(1,459
)

159,153EXPENSES:Oil and natural gas production


28,086


13,704


628





42,418Transportation expense


3,036


3





(1,384
)

1,655Depletion, depreciation and amortization


27,283


5,625


23





32,931Accretion of asset retirement obligations


827


202


15





1,044General and administrative, net of amounts capitalized


9,165


1,070


75


(75
)

10,235Total expenses


68,397


20,604


741


(1,459
)

88,283Income (loss) from operations


49,492


20,571


807





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


14,124


(2
)

(817
)




13,305Amortization of deferred loan costs


735











735Interest rate derivative losses (gains), net


2,745











2,745Commodity derivative losses (gains), net


(303,052
)










(303,052
)Total financing costs and other


(285,448
)

(2
)

(817
)




(286,267
)Equity in subsidiary income


13,395








(13,395
)

Income (loss) before income taxes


348,335


20,573


1,624


(13,395
)

357,137Income tax provision (benefit)


127,398


8,161


641





136,200Net income (loss)

$
220,937

$
12,412

$
983

$
(13,395
)
$
220,937


25

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
61,625

$
7,659

$


$


$
69,284Other


688


64


1,484


(1,377
)

859Total revenues


62,313


7,723


1,484


(1,377
)

70,143EXPENSES:Oil and natural gas production


24,641


2,702


672





28,015Transportation expense


2,425


16





(1,297
)

1,144Depletion, depreciation and amortization


20,171


1,760


43





21,974Accretion of asset retirement obligations


1,275


141


13





1,429General and administrative, net of amounts capitalized


8,787


820


80


(80
)

9,607Total expenses


57,299


5,439


808


(1,377
)

62,169Income (loss) from operations


5,014


2,284


676





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


10,267


(1
)

(939
)




9,327Amortization of deferred loan costs


751











751Interest rate derivative losses (gains), net


4,791











4,791Commodity derivative losses (gains), net


7,577











7,577Total financing costs and other


23,386


(1
)

(939
)




22,446Equity in subsidiary income


2,418








(2,418
)

Income (loss) before income taxes


(15,954
)

2,285


1,615


(2,418
)

(14,472
)Income tax provision (benefit)


(10,682
)

868


614





(9,200
)Net income (loss)

$
(5,272
)
$
1,417

$
1,001

$
(2,418
)
$
(5,272
)


26

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
339,307

$
122,531

$


$


$
461,838Other


2,419


11


3,951


(3,569
)

2,812Total revenues


341,726


122,542


3,951


(3,569
)

464,650EXPENSES:Oil and natural gas production


68,465


37,523


1,577





107,565Transportation expense


7,674


7





(3,347
)

4,334Depletion, depreciation and amortization


76,247


17,731


69





94,047Accretion of asset retirement obligations


2,426


592


47





3,065General and administrative, net of amounts capitalized


28,872


2,594


222


(222
)

31,466Total expenses


183,684


58,447


1,915


(3,569
)

240,477Income(loss) from operations


158,042


64,095


2,036





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


43,428


(16
)

(2,349
)




41,063Amortization of deferred loan costs


2,623











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


6,808











6,808Commodity derivative losses (gains), net


136,367











136,367Total financing costs and other


189,226


(16
)

(2,349
)




186,861Equity in subsidiary income


42,063








(42,063
)

Income (loss) before income taxes


10,879


64,111


4,385


(42,063
)

37,312Income tax provision (benefit)


(12,033
)

24,741


1,692





14,400Net income (loss)

$
22,912

$
39,370

$
2,693

$
(42,063
)
$
22,912


27

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
164,293

$
24,433

$


$


$
188,726Other


2,156


91


4,293


(3,993
)

2,547Total revenues


166,449


24,524


4,293


(3,993
)

191,273EXPENSES:Oil and natural gas production


67,519


11,031


1,730





80,280Transportation expense


6,651


55





(3,752
)

2,954Depletion, depreciation and amortization


58,915


6,260


90





65,265Accretion of asset retirement obligations


3,692


442


40





4,174General and administrative, net of amounts capitalized


24,119


2,045


241


(241
)

26,164Total expenses


160,896


19,833


2,101


(3,993
)

178,837Income (loss) from operations


5,553


4,691


2,192





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


33,018


(5
)

(2,731
)




30,282Amortization of deferred loan costs


2,224











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


13,691











13,691Loss on extinguishment of debt


582











582Commodity derivative losses (gains), net


9,501











9,501Total financing costs and other


59,016


(5
)

(2,731
)




56,280Equity in subsidiary income


5,964








(5,964
)

Income (loss) before income taxes


(47,499
)

4,696


4,923


(5,964
)

(43,844
)Income tax provision (benefit)


(7,955
)

1,784


1,871





(4,300
)Net income (loss)

$
(39,544
)
$
2,912

$
3,052

$
(5,964
)
$
(39,544
)


28

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

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

$
111,966

$
59,451

$
2,718

$


$
174,135CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for oil and natural gas properties


(197,123
)

(33,873
)

13





(230,983
)Acquisitions of oil and natural gas properties


(7,976
)

(2,045
)







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


(3,549
)

(42
)







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


(208,648
)

(35,960
)

13





(244,595
)CASH FLOWS FROM FINANCING ACTIVITIES:Net proceeds from (repayments of) intercompany borrowings


27,194


(24,463
)

(2,731
)




Proceeds from long-term debt


225,000











225,000Principal payments on long-term debt


(169,524
)










(169,524
)Payments for deferred loan costs


(828
)










(828
)Proceeds from derivative premium financing


7,817











7,817Proceeds from exercise of stock options


2,805











2,805Stock issuance costs


(5
)










(5
)Net cash provided by (used in) financing activities


92,459


(24,463
)

(2,731
)




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


(4,223
)

(972
)







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


8,762


973








9,735Cash and cash equivalents, end of period

$
4,539

$
1

$


$


$
4,540


29

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

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

$
64,354

$
20,366

$
4,979

$


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


(133,709
)

(12,731
)

(1,451
)




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


(21,681
)










(21,681
)Proceeds from sale of oil and natural gas properties





197,653








197,653Expenditures for property and equipment and other


(2,107
)

507








(1,600
)Net cash provided by (used in) investing activities


(157,497
)

185,429


(1,451
)




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


209,323


(205,795
)

(3,528
)




Proceeds from long-term debt


107,156











107,156Principal payments on long-term debt


(219,167
)










(219,167
)Payments for deferred loan costs


(333
)










(333
)Proceeds from Employee Stock Purchase Plan


258











258Proceeds from disgorgement of stock sale profits


15











15Proceeds from exercise of stock options


173











173Net cash provided by (used in) financing activities


97,425


(205,795
)

(3,528
)




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


4,282











4,282Cash and cash equivalents, beginning of period


190


1








191Cash and cash equivalents, end of period

$
4,472

$
1

$


$


$
4,473


30

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Table of Contents

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

The following discussion and analysis should be read in conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" contained in our Annual Report on Form 10-K for the year ended December 31, 2008 as well as with the financial statements and related notes and the
other information appearing elsewhere in this report. As used in this report, unless the context otherwise indicates, references to "we," "our," "ours," and "us" refer to Venoco, Inc. and its
subsidiaries collectively.

Overview

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural
gas properties. Our strategy is to grow through exploration, exploitation and development projects we believe to be relatively low risk and through selective acquisitions of underdeveloped properties.
Our average net production was 20,264 BOE/d in the third quarter of 2009, compared to 21,949 BOE/d in the third quarter of 2008 (19,560 BOE/d excluding production from the Hastings complex (see
"Acquisitions and Divestitures")) and 20,434 BOE/d in the second quarter of 2009. In the execution of our strategy, our management is principally focused on developing additional reserves
of oil and natural gas and on maximizing production levels through exploration, exploitation and development activities on a cost-effective basis and in a manner consistent with preserving
adequate liquidity and financial flexibility.

Capital Expenditures

We have developed an active capital expenditure program to take advantage of our extensive inventory of drilling prospects and other
projects. Our development, exploitation and exploration capital expenditure budget for 2009 is $161 million, of which approximately $130.1 million was expended in the first nine months
of 2009. We expect to spend approximately 55% of the budgeted amount on projects in the Sacramento Basin, 30% in Southern California, 6% in Texas and 9% for exploration projects in a variety of areas.
Our 2010 development, exploitation and exploration capital expenditure budget is $180 million, of which approximately 41% is expected to be deployed in the Sacramento Basin, 40% in Southern
California, 5% in Texas and the remaining 14% going towards Monterey shale exploration in Southern California. The aggregate levels of capital expenditures for the remainder of 2009 and for 2010, and
the allocation of those expenditures, are dependent on a variety of factors, including the availability of capital resources to fund the expenditures and changes in our business assessments as to
where our capital can be most profitably employed. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from our estimates. The following
summarizes certain significant aspects of our 2009 capital spending program and the outlook for 2010:

Southern CaliforniaExploitation and Development

Our primary focus in Southern California in 2009 is on development activities in the West Montalvo field, where we are continuing a
workover, recompletion and return to production program that we began when we acquired the field in May 2007. During the first nine months of 2009, we completed two wells that were spud during the
fourth quarter of 2008 and
performed six workovers and recompletions. We plan to drill two additional wells in the West Montalvo field during the fourth quarter of 2009, one of which was spud late in September. We plan to drill
three additional wells in the field during 2010, but will not realize a full year's production from successful drilling until 2011 due to timing of the drilling activity. We have more than doubled
production at West Montalvo since acquiring the field in May 2007 and anticipate an aggressive development program in the coming years.

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In
the Sockeye field, we continue to optimize our waterflood program from platform Gail. During the first nine months of the year, we drilled a dual completion well that produces from
the Monterey shale formation and expands the waterflood by injecting into the Upper Topanga formation. In 2010, we plan to drill two wells including another dual completion well that, if successful,
would produce from the Monterey shale formation and inject into the Lower Topanga formation, increasing the sweep of the waterflood in that zone. We also plan to perform our first hydraulic frac in
the offshore Monterey shale next year.

We
have a number of development opportunities in the South Ellwood field. In 2010, we expect to perform workovers and recompletions on five wells at the field. We also plan to advance
the permitting process for five proved undeveloped locations on our existing leases and perform the facilities work in order to drill those locations in 2011.

In
the South Ellwood field, the permitting process continues for our full-field development project. We have separated the permitting process into two components in order to
advance the pipeline component more quickly. We do not anticipate that approval hearings for the pipeline component will be held until mid-2010. We expect to use the pipeline to replace
the current barging operation as a means of transporting oil production from the field. Pending the completion of the pipeline, we expect to use our current barge and/or a second, double-hulled barge
(the "new barge") to transport oil production from the field. We recently obtained permits that will allow us to use the new barge, on a limited basis and subject to its other delivery commitments, if
the current barge is out of service. We are pursuing the permits necessary to use the new barge on a full-time basis, and expect to receive them no later than May 2010. Subject to the
receipt of those permits and approvals, we expect to transition to use of the new barge in connection with the termination of the contract for the current barge, which is scheduled to occur in March
2010. Our current sales agreement for oil production from the field, which became terminable in September 2009, contemplates that we will have the ability to use the new barge, subject to
availability, in the event that the current barge is unavailable.

We
also continue to pursue the lease extension component of the full-field development project. The lease extension would effectively double the size of the existing lease
area. Development of the lease extension area can be accomplished from the field's existing platform. We expect the
permitting process for the lease extension component of the project to advance independently of the permitting for the pipeline portion. We cannot assure you, however, that we will obtain the
necessary permits for either component of the project in the timeframes we expect or at all.

Sacramento BasinExploitation and Development

In the Sacramento Basin, we continue to pursue our infill drilling program in the greater Grimes and Willows fields. We expect to drill
over 60 new wells and perform approximately 200 workovers and recompletions during 2009. Our 2010 budget contemplates similar levels of drilling and workover activity.

During
the first nine months of 2009, we spud 57 wells, completed 53 (including wells spud in 2008), and performed 162 workovers and recompletions in the basin. Due in part to declining
natural gas prices, our focus in the basin in 2009 has been on drilling relatively low-risk locations rather than testing the boundary of producing areas as in previous years. We also
continue to pursue our hydraulic fracturing program in the basin, a program that we initiated in November 2007. We believe our analysis of the results to date will enable us to identify consistent
targets for future fracture stimulations in the basin.

TexasExploitation and Development

Following the sale of the Hastings complex, our largest operated field in Texas is the Manvel field. We have utilized the knowledge and
experience we gained operating the Hastings complex to

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implement
a redevelopment program for this field. This program consists mainly of returning idle wells to production, increasing the lift capacity of existing wells, working over and recompleting
existing wells in different producing sands, upgrading surface facility fluid handling capacity and increasing water injection capabilities. In addition, we are in the process of unitizing the Manvel
field and believe it is a solid candidate for a CO2 flood operation.

During
the first nine months of 2009, we performed five workovers at the Manvel field and 18 workovers at our other Texas properties. We anticipate performing an additional four to five
workovers during the fourth quarter. We spud a well in the South Liberty field during the third quarter. We
completed drilling the well in October and continue to evaluate all zones from which the well could produce. Our 2010 capital budget includes capital to participate in four new development wells and
return five wells to production in Texas.

Exploration Activities

In 2006 we began actively leasing onshore acreage in Southern California targeting the Monterey shale formation. Our leasing strategy
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 is approaching 100,000 net acres. We intend to add to this position in the remainder of 2009 and in 2010. We plan to drill five onshore Monterey shale wells in 2010.

Acquisitions and Divestitures

Sacramento Basin Asset Acquisition.On June 30, 2009, we closed on the acquisition of certain natural gas producing properties in
the
Sacramento Basin, which we purchased from Aspen Exploration Corporation and certain other parties for approximately $21.4 million. We paid for this acquisition with cash on hand and
approximately $18.9 million in borrowings under our revolving credit facility. See further discussion of this acquisition in Note 2 to the Condensed Consolidated Financial Statements.

Hastings Sale.In February 2009, we completed the sale of our principal interests in the Hastings complex to Denbury for approximately
$197.7 million. We retained an overriding royalty and a reversionary interest in the complex. As a result of the sale, we repaid all amounts then outstanding under our revolving credit facility
and paid $5.5 million of the outstanding principal balance on our second lien term loan facility.

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

Certain Trends Affecting our Results of Operations

Oil and Natural Gas Prices.Historically, prices received for our oil and natural gas production have been volatile and unpredictable,
and that
volatility is expected to continue. Changes in the market prices for oil and natural gas directly impact many aspects of our business, including our financial condition, revenues, results of
operations, liquidity, rate of growth, the carrying value of our oil and natural gas properties and borrowing capacity under our revolving credit facility, all of which depend primarily or in part
upon those prices. For example, as a result of lower commodity prices at December 31, 2008, we were required to record a full cost ceiling impairment of our oil and gas properties in the fourth
quarter. Future reductions in commodity prices may require us to record further ceiling impairments of our oil and natural gas properties. Continued low prices in early 2009 contributed significantly
to a February 2009 reduction in the borrowing base under our revolving credit facility. In order to reduce the variability of the prices we receive for our production and provide a minimum revenue
stream, we employ a hedging strategy. As of September 30, 2009, we had hedge

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contract
floors covering approximately 95% of our 2009 annual production guidance and a significant portion of our expected production in 2010 and 2011. We have also begun to secure hedge contracts
for our 2012 production. All of our derivatives counterparties are members, or affiliates of members, of our revolving credit facility syndicate. See "Quantitative and Qualitative Disclosures About
Market RiskCommodity Derivative Transactions" for further details concerning our hedging activities.

Expected Production.We expect that the execution of our 2009 capital expenditure program will result in average daily production
volumes in 2009 of
approximately 20,250 BOE/d compared to 19,088 BOE/d for 2008, pro forma for the Hastings sale. In 2010, we intend to emphasize the development of our robust inventory of oil projects, primarily at our
Southern California properties. Because some of these projects will require significant time for implementation, much of the production growth we expect from those projects will not be realized until
after 2010. Accordingly, while we believe that these projects, if successful, will result in significant production growth in subsequent years, we expect our average daily production in 2010 will be
approximately the same as in 2009, or approximately 20,250 BOE/d. Our expectations with respect to future production rates are subject to a number of uncertainties, including those associated with
third party services, oil and natural gas prices, events
resulting in unexpected downtime, permitting issues, drilling success rates, pipeline capacity, changes in our capital expenditure budget and other factors, including those referenced in "Risk
Factors".

Production Expenses.Production expenses consist of lease operating expenses ("LOE") and production and property taxes. LOE per BOE
decreased from
$16.03 per BOE for the first nine months of 2008 to $12.59 per BOE in the first nine months of 2009. We expect our 2010 LOE per BOE to increase slightly relative to 2009. We expect 2010
production/property taxes to remain relatively flat on a per BOE basis, compared to our 2009 results. 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 decreased from $4.64 per BOE for the first nine months of 2008
(excluding
share-based compensation charges of $0.29 per BOE and non-recurring charges of $0.46 per BOE relating to the termination of a planned master limited partnership ("MLP") offering), to $4.34
per BOE (excluding share-based compensation charges of $0.26 per BOE) in the first nine months of 2009. Excluding share-based compensation charges, on a per BOE basis, we expect our 2010 G&A costs to
be similar to our 2009 results. As with production expenses, our expectations with respect to G&A costs are subject to numerous risks and uncertainties.

Depreciation, Depletion and Amortization (DD&A).DD&A decreased from $16.09 per BOE for the first nine months of 2008 to $11.49
per BOE in the first
nine months of 2009. The decrease is due to a reduced amortizable base as a result of the full cost ceiling write down recorded at December 31, 2008 and the application of proceeds from the
sale of the Hastings complex in February 2009 to reduce the full cost pool. We expect our 2010 DD&A to increase slightly on a per BOE basis, compared to our 2009 results. As with production and G&A
expenses, our expectations with respect to DD&A are subject to numerous risks and uncertainties.

Unrealized Derivative Gains and Losses.Decreases in both oil and natural gas prices led to significant unrealized commodity derivative
gains in the
first quarter of 2009, while increases in oil prices resulted in unrealized commodity derivative losses in the second and third quarters of 2009. These unrealized gains and losses resulted from
mark-to-market valuations of derivative positions that are not accounted for as cash flow hedges and are reflected as unrealized commodity derivative gains 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 gains and losses of this type in recent periods and may continue to incur these types of gains and losses in the future. We may also have significant

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unrealized
interest rate derivative gains and losses in subsequent periods due to changes in market interest rates.

Results of Operations

The following table reflects the components of our oil and natural gas production and sales prices and sets forth our operating
revenues, costs and expenses on a BOE basis for the three and nine months ended September 30, 2008 and 2009.

Three Months Ended
September 30,

Nine Months Ended
September 30,2008

2009

2008

2009Production Volume:Oil (MBbls)(1)


1,036


811


2,995


2,593Natural gas (MMcf)


5,900


6,320


17,110


18,518MBOE


2,019


1,864


5,846


5,679Daily Average Production Volume:Oil (Bbls/d)


11,261


8,815


10,931


9,498Natural gas (Mcf/d)


64,130


68,696


62,445


67,832BOE/d


21,949


20,264


21,339


20,803Oil Price per Bbl Produced (in dollars):Realized price

$
109.08

$
58.09

$
104.81

$
46.80Realized commodity derivative gain (loss)


(32.08
)

(4.66
)

(29.69
)

1.90Net realized price

$
77.00

$
53.43

$
75.12

$
48.70Natural Gas Price per Mcf (in dollars):Realized price

$
8.92

$
3.17

$
9.07

$
3.59Realized commodity derivative gain (loss)


(0.15
)

3.24


(0.08
)

2.76Net realized price

$
8.77

$
6.41

$
8.99

$
6.35Expense per BOE:Lease operating expenses(2)

$
17.89

$
13.55

$
16.03

$
12.59Production and property taxes(2)


3.12


1.48


2.37


1.55Transportation expenses


0.82


0.61


0.74


0.52Depreciation, depletion and amortization


16.31


11.79


16.09


11.49General and administrative expense(3)


5.07


5.15


5.38


4.61Interest expense


6.59


5.00


7.02


5.33


(1)Amounts
shown are oil production volumes for offshore properties and sales volumes for onshore properties (differences between onshore production and sales
volumes are minimal). Revenue accruals for offshore properties are adjusted for actual sales volumes since offshore oil inventories can vary significantly from month to month based on the timing of
barge deliveries, oil in tank and pipeline inventories, and oil pipeline sales nominations.(2)Lease
operating expenses are combined with property and production taxes to comprise oil and natural gas production expense on the condensed consolidated
statements of operations.(3)Net
of amounts capitalized.


Comparison of Quarter Ended September 30, 2009 to Quarter Ended September 30, 2008

Oil and Natural Gas Sales.Oil and natural gas sales decreased $88.7 million (56%) to $69.3 million for the quarter ended
September 30, 2009 from $158.0 million for the same period in

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2008.
The decrease was primarily due to a decrease in average sales prices and a slight decrease in production as described below.

Oil
sales decreased by $56.2 million (53%) in the third quarter of 2009 to $49.2 million compared to $105.4 million in the third quarter of 2008. Oil production
decreased by 22%, with production of 811 MBbl in the third quarter of 2009 compared to 1,036 MBbl in the third quarter of 2008. The production decrease was primarily due to the sale of the Hastings
complex in early February 2009. Excluding Hastings, production was relatively flat at 811 MBbl in the third quarter of 2009 compared to 817 MBbl in the third quarter of 2008. Production at the West
Montalvo field increased in the third quarter of 2009 compared to the third quarter of 2008 as a result of recompletion and drilling efforts. The increases at West Montalvo were offset by lower
production at the Sockeye field due to wells that were down during the third quarter of 2009. South Ellwood production remained relatively constant between periods as a result of reduced production in
both periods due to barge maintenance in the third quarter of 2008 and scheduled maintenance at Platform Holly in the third quarter of 2009. Our average realized price for oil decreased $50.99 (47%)
to $58.09 per Bbl for the period.

Natural
gas sales decreased $32.6 million (62%) in the third quarter of 2009 to $20.0 million compared to $52.6 million in the third quarter of 2008. Natural gas
production increased 7%, with production of 6,320 MMcf in the third quarter of 2009 compared to 5,900 MMcf in the third quarter of 2008. The increase was due primarily to drilling and recompletion
activities in the Sacramento Basin as well as production from wells acquired in the Aspen acquisition. Our average realized price for natural gas decreased $5.75 (64%) to $3.17 per Mcf for the period.

Other Revenues.Other revenues were relatively consistent at $1.1 million in the third quarter of 2008 and $0.9 million in
the third
quarter of 2009.

Production Expenses.Production expenses, which consist of lease operating expenses ("LOE") and production/property taxes, decreased
$14.4 million (34%) to $28.0 million in the third quarter of 2009 from $42.4 million in the third quarter of 2008. The decrease was primarily due to the sale of Hastings in early
February 2009 which was historically a relatively high cost field. On a per unit basis, LOE decreased to $13.55 per BOE in the third quarter of 2009 from $17.89 per BOE in the same period in 2008.
Excluding Hastings, LOE per BOE decreased $1.49 from $15.04 per BOE in the third quarter of 2008 to $13.55 per BOE in the third quarter of 2009. The decrease is partially due to the increased
proportion of Sacramento Basin natural gas production during the third quarter of 2009, which has lower operating costs than oil production. Additionally, we incurred relatively high
non-recurring maintenance costs related to certain wells in the Sockeye field in the third quarter of 2008, which were not incurred in the third quarter of 2009. The decreases were
partially offset by costs incurred in the third quarter of 2009 related to scheduled maintenance performed on Platform Holly in the South Ellwood field. We also continue to pursue price/cost
reductions from external contractors and suppliers.

Transportation Expenses.Transportation expenses decreased $0.6 million (31%) to $1.1 million in the third
quarter of 2009 from $1.7 million in the third quarter of 2008. On a per BOE basis, transportation expenses decreased $0.21 per BOE, from $0.82 per BOE in the third quarter of 2008 to $0.61 per
BOE in the third quarter of 2009. The decrease is primarily due to maintenance costs incurred in the third quarter of 2008 related to the barge that transports South Ellwood oil production.

Depletion, Depreciation and Amortization (DD&A).DD&A expense decreased $10.9 million (33%) to $22.0 million in the
third quarter of
2009 from $32.9 million in the third quarter of 2008. DD&A expense decreased $4.52 per BOE, from $16.31 per BOE in the third quarter of 2008 to $11.79 per BOE in the third quarter of 2009. The
decrease is due to a reduced depletable base as a result of the full cost ceiling write down recorded at December 31, 2008 and the application of proceeds from the sale of the Hastings complex
in February 2009 to reduce the full cost pool.

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Accretion of Abandonment Liability.Accretion expense increased $0.4 million (37%) to $1.4 million in the third quarter of
2009 from
$1.0 million in the third quarter of 2008. The increase was due to revisions to estimated liabilities recorded in the fourth quarter of 2008 and accretion from new wells drilled and completed
in the last half of 2008 and the first nine months of 2009.

General and Administrative (G&A).G&A expense decreased $0.6 million (6%) to $9.6 million in the third quarter of
2009 from
$10.2 million in the third quarter of 2008. Non-cash share-based compensation expense charged to G&A was $0.6 million for both the third quarter of 2008 and the third quarter
of 2009. Excluding the effect of the non-cash share-based compensation expense, G&A expense remained relatively consistent at $4.80 per BOE in the third quarter of 2008 and $4.82 per BOE
in the third quarter of 2009.

Interest Expense, Net.Interest expense, net of interest income, decreased $4.0 million (30%) from $13.3 million in the third
quarter
of 2008 to $9.3 million in the third quarter of 2009. The decrease was primarily the result of a reduction in our average debt outstanding and lower interest rates realized during the third
quarter of 2009.

Amortization of Deferred Loan Costs.Amortization of deferred loan costs remained constant at $0.7 million for the third quarter of
2008 and
$0.8 million for the third quarter of 2009.

Interest Rate Derivative (Gains) Losses, Net.Changes in the fair value of our interest rate swap derivative instruments resulted in
unrealized
losses of nil in the third quarter of 2009 and unrealized gains of $0.6 million in the 2008 period. Unrealized interest rate (gains) losses represent the change in the fair value of our
interest rate derivative contracts from period to period based on estimated future interest rates at the end of the reporting period. Realized interest rate swap losses were $4.8 million in the
third quarter of 2009 compared to realized losses of $3.4 million in the third quarter of 2008.

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

Three Months Ended
September 30,2008

2009Realized commodity derivative (gains) losses

$
34,095

$
(16,675
)Amortization of commodity derivative premiums


1,626


5,999Unrealized commodity derivative (gains) losses for changes in fair value


(338,773
)

18,253Commodity derivative (gains) losses

$
(303,052
)
$
7,577


Realized
commodity derivative gains or losses represent the difference between the strike prices in the contracts settled during the period and the ultimate settlement prices. The
realized commodity derivative gains in the third quarter of 2009 reflect the settlement of contracts at prices below the relevant strike prices, while the realized derivative losses in the third
quarter of 2008 reflects the settlement of contracts at prices above 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 provided a valuation allowance against our net deferred tax assets at December 31, 2008 and
September 30, 2009 since we could not conclude that it is more likely than not that the net deferred tax assets will be recognized. The current tax benefit for the third quarter of 2009 of
$9.2 million reflects a reduction of prior year current tax expense (a $6.6 million benefit) and a federal AMT and state income tax benefit of $2.6 million related to lower
current

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earnings.
The net income for the third quarter of 2008 resulted in an income tax expense of $136.2 million.

Net Income (Loss).Net loss for the third quarter of 2009 was $5.3 million compared to net income of $220.9 million for the
same period
in 2008. The change between periods is the result of the items discussed above.

Comparison of Nine months Ended September 30, 2009 to Nine months Ended September 30, 2008

Oil and Natural Gas Sales.Oil and natural gas sales decreased $273.1 million (59%) to $188.7 million for the nine months
ended
September 30, 2009 from $461.8 million for the same period in 2008. The decrease was primarily due to a decrease in average sales prices as production remained relatively constant
between the two periods, as described below.

Oil
sales decreased by $184.5 million (60%) for the first nine months of 2009 to $122.2 million compared to $306.7 million in the nine months of 2008. Oil production
decreased by 13% with production of 2,593 MBbl in the first nine months of 2009 compared to 2,995 MBbl in the first nine months of 2008. The production decrease was primarily due to the sale of the
Hastings complex in early February 2009. Excluding Hastings, production increased 219 MBbl (10%) from 2,293 MBbl in the first nine months of 2008 to 2,512 MBbl in the first nine months of 2009. The
increase is primarily due to increased production at the West Montalvo and Sockeye fields as a result of drilling and recompletion activities in the latter half of 2008 and the first nine months of
2009. Our average realized price for oil decreased $58.01 (55%) to $46.80 per Bbl for the period.

Natural
gas sales decreased $88.6 million (57%) in the first nine months of 2009 to $66.5 million compared to $155.1 million in the first nine months of 2008.
Natural gas production increased 8%, with production of 18,518 MMcf in the first nine months of 2009 compared to 17,110 MMcf in the first nine months of 2008. The increase was due primarily to
drilling and recompletion activities in the Sacramento Basin. Our average realized price for natural gas decreased $5.48 (60%) to $3.59 per Mcf for the period.

Other Revenues.Other revenues were relatively consistent at $2.8 million in the first nine months of 2008 and $2.5 million in
the
first nine months of 2009.

Production Expenses.Production expenses, which consist of lease operating expenses ("LOE") and production/property taxes, decreased
$27.3 million (25%) to $80.3 million in the first nine months of 2009 from $107.6 million in the first nine months of 2008. The decrease was primarily due to the sale of Hastings
in early February 2009 which was historically a relatively high cost field. On a per unit basis, LOE decreased to $12.59 per BOE in the first nine months of 2009 from $16.03 per BOE in the same period
in 2008. Excluding Hastings, LOE per BOE decreased $1.20 from $13.68 per BOE in the first nine months of 2008 to $12.48 per BOE in the first nine months of 2009. In the first nine months of 2008, we
incurred relatively high non-recurring maintenance costs related to certain wells in the Sockeye field, which were not incurred in the first nine months of 2009. Additionally, we incurred
scheduled maintenance costs in the 2008 period related to Platform Gail in the Sockeye field. We did not incur these costs in 2009. We also continue to pursue price/cost reductions from external
contractors and suppliers.

Transportation Expenses.Transportation expenses decreased $1.3 million (32%) to $3.0 million in the first nine months of
2009 from
$4.3 million in the first nine months of 2008. On a per BOE basis, transportation expenses decreased $0.22 per BOE, from $0.74 per BOE in the first nine months of 2008 to $0.52 per BOE in the
first nine months of 2009. The decrease is primarily due to maintenance costs incurred in the first nine months of 2008 related to the barge that transports South Ellwood oil production.

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Depletion, Depreciation and Amortization (DD&A).DD&A expense decreased $28.7 million (31%) to $65.3 million in the
first nine months
of 2009 from $94.0 million in the first nine months of 2008. DD&A expense decreased $4.60 per BOE, from $16.09 per BOE in the first nine months of 2008 to $11.49 per BOE in the first nine
months of 2009. The decrease is due to a reduced depletable base as a result of the full cost ceiling write down recorded at December 31, 2008 and the application of proceeds from the sale of
the Hastings complex in February 2009 to reduce the full cost pool.

Accretion of Abandonment Liability.Accretion expense increased $1.1 million (36%) to $4.2 million in the first nine months of
2009
from $3.1 million in the first nine months of 2008. The increase was due to revisions to estimated liabilities recorded in the fourth quarter of 2008 and accretion from new wells drilled and
completed in 2008 and the first nine months of 2009.

General and Administrative (G&A).G&A expense decreased $5.3 million (17%) to $26.2 million in the first nine months
of 2009 from
$31.5 million in the first nine months of 2008. The decrease is primarily related to $2.7 million of costs that were expensed in the second quarter of 2008 related to the cancellation of
a planned MLP offering. Additionally, we incurred lower legal and professional fees in the first nine months of 2009 compared to the same period in 2008. The decrease also resulted from an increase in
the G&A costs that were capitalized in 2009 for payroll and related overhead for activities that are directly involved in our development, exploitation, exploration and acquisition efforts.
Non-cash share-based compensation expense charged to G&A decreased $0.2 million (11%) from $1.7 million in 2008 to $1.5 million in 2009, primarily as a result of
certain awards that became fully vested in the first quarter of 2009. Excluding the effect of the non-cash share-based compensation expense charges and MLP write-off charges,
G&A expense decreased $0.30 from $4.64 per BOE in the first nine months of 2008 to $4.34 per BOE in the first nine months of 2009.

Interest Expense, Net.Interest expense, net of interest income, decreased $10.8 million (26%) from $41.1 million in the first
nine
months of 2008 to $30.3 million in the first nine months of 2009. The decrease was primarily the result of a reduction in our average debt outstanding and lower interest rates realized during
the first nine months of 2009.

Amortization of Deferred Loan Costs.Amortization of deferred loan costs decreased $0.4 million, from $2.6 million in the
first nine
months of 2008 to $2.2 million in the first nine months of 2009. The decrease was primarily due to the amendment to the revolving credit facility in May 2008 which extended the maturity date of
the facility.

Interest Rate Derivative (Gains) Losses, Net.Changes in the fair value of our interest rate swap derivative instruments resulted in
unrealized gains
of $0.2 million in the first nine months of 2009 and unrealized gains of $0.3 million in the 2008 period. Unrealized interest rate (gains) losses represent the change in the fair value
of our interest rate derivative contracts from period to period based on estimated future interest rates at the end of the reporting period. Realized interest rate swap losses were
$13.9 million in the first nine months of 2009 compared to realized losses of $7.1 million in the first nine months of 2008.

Loss on Extinguishment of Debt.We recognized a loss on extinguishment of debt in the first nine months of 2009 of $0.6 million
related to
repayment of the financed derivative premiums balance in May 2009.

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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):

Nine Months Ended
September 30,2008

2009Realized commodity derivative (gains) losses

$
90,214

$
(63,748
)Amortization of commodity derivative premiums


5,155


16,662Unrealized commodity derivative (gains) losses for changes in fair value


40,998


56,587Commodity derivative (gains) losses

$
136,367

$
9,501


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 2009 period reflect the settlement of contracts at prices below the relevant strike prices, while the realized derivative losses in the 2008 period reflect
the settlement of contracts at prices above the relevant strike prices. In addition, in the first quarter of 2009, we unwound certain oil collars and purchased oil swaps with the proceeds. We also
unwound certain 2009 gas puts to bring our hedge position in line with our production guidance. As a result of these transactions, we realized non-recurring gains of $7.7 million
which are reflected in realized commodity derivative (gains) losses. Unrealized commodity derivative (gains) losses represent the change in the fair value of our open derivative contracts from period
to period. Derivative premiums are amortized over the term of the underlying derivative contracts.

Income Tax Expense (Benefit).We provided a valuation allowance against our net deferred tax assets at December 31, 2008 and
September 30, 2009 since we could not conclude that it is more likely than not that the net deferred tax assets will be recognized. The current tax benefit for the first nine months of 2009 of
$4.3 million reflects a reduction of prior year current tax expense (a $6.6 million benefit) partially offset by federal AMT (mostly related to the Hastings transaction) and state income
tax expense of $2.3 million. The net income for the first nine months of 2008 resulted in an income tax expense of $14.4 million.

Net Income (Loss).Net loss for the first nine months of 2009 was $39.5 million compared to net income of $22.9 million for
the same
period in 2008. The change between periods is the result of the items discussed above.

Liquidity and Capital Resources

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

Cash Flows

Nine Months Ended
September 30,2008

2009(in thousands)Cash provided by operating activities

$
174,135

$
89,699Cash (used in) provided by investing activities


(244,595
)

26,481Cash (used in) provided by financing activities


65,265


(111,898
)


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Net
cash provided by operating activities was $89.7 million in the first nine months of 2009 compared with $174.1 million in the first nine months of 2008. Cash flows from
operating activities in the first nine months of 2009 as compared to the first nine months of 2008 were unfavorably impacted by significant decreases in commodity prices.

Net
cash provided by investing activities was $26.5 million in the first nine months of 2009 compared with $244.6 million used in the first nine months of 2008. The primary
investing activities in the first nine months of 2009 were receipt of $197.7 million in cash proceeds from the sale of the Hastings complex offset by $147.9 million in capital
expenditures on oil and natural gas properties related to our capital expenditure program and $21.3 million paid to acquire certain Sacramento Basin assets. The primary investing activities in
the first nine months of 2008 include $241.0 million in capital expenditures on oil and natural gas properties.

Net
cash used in financing activities was $111.9 million in the first nine months of 2009 compared to $65.3 million provided by financing activities in the first nine
months of 2008. The primary financing activities in the first nine months of 2009 were $90.1 million in net payments made on our revolving
credit facility and $5.5 million of principal payments on the second lien term loan, both of which were primarily funded with proceeds from the Hastings sale. Additionally, we paid
approximately $15.3 million in May 2009 to settle financed derivative premiums. Financing activities in the first nine months of 2008 included $58.0 million in net borrowings under our
revolving credit facility to fund capital expenditures and working capital needs.

Capital Resources and Requirements

We plan to make substantial capital expenditures in the future for the acquisition, exploration, exploitation and development of oil
and natural gas properties. We expect that our exploration, exploitation and development capital expenditures will be approximately $161 million in 2009. We intend to finance our capital
expenditures for the remainder of the year with cash flow from operations. As of November 2, 2009, there was $54.3 million outstanding under our credit facility. We do not currently
expect to borrow any significant additional amounts under the revolving credit facility during the remainder of 2009. Consequently, we expect to maintain additional borrowing capacity under the
facility, although our ability to access those funds could be constrained by our need to remain in compliance with the debt to EBITDA covenant described below and the possibility that continued
weakness in natural gas prices and volatility in oil prices could result in a reduction in the borrowing base. In 2010, we expect to fund our capital expenditure budget of $180 million
primarily with cash flow from operations, supplemented with proceeds from capital raising transactions that may include asset sales, joint venture transactions and/or issuance of equity. In
particular, we will seek to finance part of the planned capital expenditures relating to our Monterey shale development project through a joint venture. If we are unable to complete one or more of
those transactions on terms acceptable to us, we would currently expect to reduce our capital expenditure budget. Uncertainties relating to our capital resources and requirements in 2009 and 2010
include the possibility that one or more of the counterparties to our hedging arrangements fails to perform under the contracts, the effects of changes in commodity prices and differentials and the
possibility that we will pursue one or more significant acquisitions that would require additional debt or equity financing.

Amended Revolving Credit Facility.We entered into a second amended and restated agreement governing our revolving credit facility in
March 2006, and
have entered into several subsequent amendments to the agreement. 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 2009 or 2010, we believe

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that
it will be important to monitor the debt to EBITDA ratio requirement, especially if our EBITDA is less than we expect due to operational problems or other factors, or if our borrowing needs are
greater than we expect. The agreement requires us to reduce amounts outstanding under the facility with the proceeds of certain transactions or events, including sales of assets, in certain
circumstances. The revolving credit facility is secured by a first priority lien on substantially all of our assets.

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

The
revolving credit facility has a total capacity of $300.0 million, but is limited by a borrowing base currently established at $125.0 million. The borrowing base is
subject to redetermination twice each year, and may be redetermined at other times at our request or at the request of the lenders. In connection with a June 2009 amendment that adjusted the interest
rates associated with the facility, the borrowing base was reaffirmed at $125.0 million. Lending commitments under the facility have been allocated at various percentages to a syndicate of
twelve banks. Certain of the institutions included in the syndicate have received support from governmental agencies in connection with recent events in the credit markets. In addition, 4.75% of the
borrowing base has been allocated to Lehman Commercial Paper, Inc. ("LCP"), a wholly-owned subsidiary of Lehman Brothers Holdings, Inc., which filed for bankruptcy protection in
September 2008. LCP is no longer funding its portion of our borrowing requests made under the facility. Accordingly, our effective borrowing base is $119.1 million, excluding
$5.9 million related to LCP. A failure of any other member of the syndicate to fund under the facility, or a reduction in the borrowing base, would adversely affect our liquidity. As a result
of the Hastings sale in February 2009, we repaid the then outstanding balance of the facility in full. Subsequently, we have borrowed approximately $54.3 million (net of principal repayments)
through November 2, 2009, to finance certain derivative premiums, fund the Sacramento Basin asset acquisition, to satisfy and discharge the 8.75% senior notes (see below) and to fund other
operating needs.

Second Lien Term Loan.We entered into a $500.0 million senior secured second lien term loan agreement in May 2007. The term loan
agreement
contains customary representations, warranties, events of default and indemnities and certain customary operational covenants, including covenants that restrict our ability to incur additional
indebtedness. The agreement requires us to maintain derivative contracts covering at least 70% of our projected oil and natural gas production attributable to proved developed producing reserves
through May 8, 2010, and at least 50% of such production on an annual basis until the maturity date of the term loan. We cannot, however, enter into derivative contracts (other than certain put
contracts) covering more than 80% of such projected oil and gas production in any month. The agreement also prohibits us from paying dividends on our common stock. The agreement will require us to
make offers to prepay amounts outstanding under the second lien term loan facility with the proceeds of certain transactions or events, including sales of assets, in certain circumstances. Amounts
prepaid under the facility may not be reborrowed. The term loan facility is secured by a second priority lien on substantially all of our assets. We repaid $5.5 million of principal under the
facility in February 2009 after the Hastings sale. Under the terms of the second lien term loan agreement, if the 8.75% senior notes were outstanding on September 20, 2011, the principal on the
facility would be due on that date. However, as a result of the refinancing of our 8.75% senior notes
described below, the maturity date of the principal on the second lien term loan will be extended to May 8, 2014.

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Loans under the term loan facility designated as "Base Rate Loans" bear interest at a floating rate equal to (i) the greater of the overnight federal funds
rate plus 0.50% and the administrative agent's announced base rate, plus (ii) 3.00%. Loans designated as "LIBO Rate Loans" bear interest at LIBOR plus 4.00%. As of September 30, 2009, we
have entered into interest rate swaps pursuant to which amounts borrowed under the term loan agreement will effectively bear interest at a fixed rate of approximately 8.0% until September 2011. In
October 2009, we entered into a series of transactions which extended the existing interest rate swap until May 7, 2014 at a weighted average rate of 3.84%, which reduces our fixed interest
rate to approximately 7.8%. See "Quantitative and Qualitative Disclosures About Market RiskInterest Rate Derivative Transactions."

Senior Notes.We issued $150.0 million of our 8.75% senior notes in December 2004. Prior to the satisfaction and discharge of the
8.75% senior
notes as described below, those notes bore interest at 8.75% per year and were due to mature on December 15, 2011. The indenture governing the notes contained operational covenants that, among
other things, limited our ability to make investments, incur additional indebtedness or create liens on our assets. The notes were secured with the second lien term loan on an equal and ratable basis.

In
October 2009, we issued $150.0 million in 11.50% senior notes due October 2017 at a price of 95.03% of par. Concurrently with the sale of the 11.50% senior notes, we
irrevocably deposited $159.8 million in cash with the trustee under the indenture governing the 8.75% senior notes, thus
effecting a satisfaction and discharge of the 8.75% senior notes. Additionally, we issued an irrevocable notice of redemption to call the 8.75% senior notes for redemption at 102.188% on
December 15, 2009. The funds deposited with the trustee are sufficient to pay the aggregate redemption price and all accrued interest on the 8.75% senior notes as of the redemption date.

We
may redeem the 11.50% 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 11.50% senior notes are senior unsecured obligations. The indenture governing
the 11.50% senior notes contains covenants similar to those in the indenture that governed the 8.75% senior notes.

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

Off-Balance Sheet Arrangements

At September 30, 2009, we had no existing off-balance sheet arrangements, as defined under SEC rules, that have or
are reasonably likely to have a material current or future effect on our financial

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condition,
revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Item 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

This section provides information about derivative financial instruments we use to manage commodity price volatility. Due to the
historical volatility of crude oil and natural gas prices, we have implemented a hedging strategy aimed at reducing the variability of the prices we receive for our production and providing a minimum
revenue stream. Currently, we purchase puts and enter into other derivative transactions such as collars and fixed price swaps in order to hedge our exposure to changes in commodity prices. All
contracts are settled with cash and do not require the delivery of a physical quantity to satisfy settlement. While this hedging strategy may result in us having lower revenues than we would have if
we were unhedged in times of higher oil and natural gas prices, management believes that the stabilization of prices and protection afforded us by providing a revenue floor on a portion of our
production is beneficial. 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.

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

Commodity Derivative Transactions

Oil.As of September 30, 2009, we had entered into derivative agreements to receive average minimum and maximum NYMEX West Texas
Intermediate
prices as summarized below. Location and quality differentials attributable to our properties are not reflected in those prices. The agreements provide for monthly settlement based on the difference
between the agreement price and the actual NYMEX crude oil price.

MinimumMaximumAvg. PricesBarrels/day

Barrels/day

Avg. PricesCrude oil derivatives at September 30, 2009 for production:October 1 - December 31, 2009


8,750

$
56.41


6,750

$
63.80January 1 - December 31, 2010


8,000

$
56.22


6,150

$
72.88January 1 - December 31, 2011


7,000

$
50.00


7,000

$
141.64


Natural Gas Agreements.As of September 30, 2009, we had entered into option, swap and collar agreements to receive average
minimum and
maximum NYMEX or PG&E Citygate prices as follows:

Minimum

MaximumMMBtu/Day

Avg. Prices

MMBtu/Day

Avg. PricesNatural gas derivatives at September 30, 2009 for production:October 1 - December 31, 2009


61,125

$
7.02


23,125

$
11.39January 1 - December 31, 2010


58,900

$
6.48


27,900

$
9.26January 1 - December 31, 2011


36,000

$
6.59


12,000

$
13.77January 1 - December 31, 2012


23,300

$
6.00


15,500

$
9.10


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Table of Contents

Portfolio of Derivative Transactions

Our portfolio of commodity derivative transactions as of September 30, 2009 is summarized below:

Oil

Type of Contract

Counterparty

Basis

Quantity
(Bbl/d)

Strike Price
($/Bbl)

TermSwap

Bank of Montreal

NYMEX


1,000


$59.75


Oct 1 - Dec 31, 09Swap

Fortis Bank

NYMEX


2,000


$67.22


Oct 1 - Dec 31, 09Swap

Bank of Montreal

NYMEX


3,000


$58.14


Oct 1 - Dec 31, 09Collar

Bank of Montreal

NYMEX


750


$60.00/$82.75


Oct 1 - Dec 31, 09Put

Bank of Montreal

NYMEX


2,000


$40.00


Oct 1 - Dec 31, 09Collar

Bank of Oklahoma

NYMEX


3,500


$60.00/$73.00


Jan 1 - Dec 31, 10Swap

Fortis Bank

NYMEX


1,000


$66.75


Jan 1 - Dec 31, 10Collar

Fortis Bank

NYMEX


1,000


$60.00/$72.80


Jan 1 - Dec 31, 10Collar

Bank of Montreal

NYMEX


650


$60.00/$81.75


Jan 1 - Dec 31, 10Put

Scotia Bank

NYMEX


1,850


$40.00


Jan 1 - Dec 31, 10Collar

Key Bank

NYMEX


2,000


$50.00/$141.00


Jan 1 - Dec 31, 11Collar

Key Bank

NYMEX


2,000


$50.00/$144.75


Jan 1 - Dec 31, 11Collar

Credit Suisse

NYMEX


3,000


$50.00/$140.00


Jan 1 - Dec 31, 11


Natural Gas

Type of Contract

Counterparty

Basis

Quantity
(MMBtu/d)

Strike Price
($/MMBtu)

TermBasis Swap

Bank of Montreal

PG&E Citygate


6,000


$0.10


Oct 1 - Dec 31, 09Basis Swap

Bank of Montreal

PG&E Citygate


7,500


$0.11


Oct 1 - Dec 31, 09Collar

Bank of Montreal

NYMEX


1,125


$8.00/$12.00


Oct 1 - Dec 31, 09Collar

Bank of Montreal

NYMEX


4,000


$7.30/$9.85


Oct 1 - Dec 31, 09Collar

Bank of Montreal

NYMEX


7,000


$7.50/$12.75


Oct 1 - Dec 31, 09Collar

Credit Suisse

NYMEX


8,500


$7.50/$11.15


Oct 1 - Dec 31, 09Put

Credit Suisse

NYMEX


10,000


$8.50


Oct 1 - Dec 31, 09Put

Credit Suisse

NYMEX


28,000


$6.00


Oct 1 - Dec 31, 09Basis Swap

Credit Suisse

PG&E Citygate


19,625


$0.00 (flat
)

Oct 1 - Dec 31, 09Swap

Credit Suisse

NYMEX


1,250


$8.00


Oct 1 - Dec 31, 09Collar

Credit Suisse

NYMEX


1,250


$7.25/$11.30


Oct 1 - Dec 31, 09Basis Swap

Bank of Montreal

PG&E Citygate


6,475


$0.14


Oct 1 - Dec 31, 09Collar

Bank of Montreal

NYMEX


1,000


$7.00/$9.10


Jan 1 - Dec 31, 10Collar

Bank of Montreal

NYMEX


900


$7.50/$12.20


Jan 1 - Dec 31, 10Put

Bank of Montreal

NYMEX


41,000


$6.00


Jan 1 - Dec 31, 10Basis Swap

Bank of Montreal

PG&E Citygate


7,718


$0.09


Jan 1 - Dec 31, 10Collar

Bank of Oklahoma

NYMEX


10,000


$7.00/$10.35


Jan 1 - Dec 31, 10Basis Swap

Bank of Oklahoma

PG&E Citygate


10,000


$0.22


Jan 1 - Dec 31, 10Collar

Credit Suisse

NYMEX


6,000


$7.50/$11.95


Jan 1 - Dec 31, 10Basis Swap

Credit Suisse

PG&E Citygate


7,900


$0.05


Jan 1 - Dec 31, 10Basis Swap

Credit Suisse

PG&E Citygate


12,000


$0.20


Jan 1 - Dec 31, 10Call Spread

RBS

NYMEX


10,000


$10.35/$9.00


Jan 1 - Dec 31, 10Call Spread

RBS

NYMEX


900


$12.20/$9.00


Jan 1 - Dec 31, 10Call Spread

Credit Suisse

NYMEX


6,000


$11.95/$9.00


Jan 1 - Dec 31, 10Call

RBS

NYMEX


10,000


$9.00


Jan 1 - Dec 31, 10Basis Swap

Key Bank

PG&E Citygate


14,000


$0.10


Jan 1 - Dec 31, 10


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Table of Contents

Type of Contract

Counterparty

Basis

Quantity
(MMBtu/d)

Strike Price
($/MMBtu)

TermCollar

Credit Suisse

NYMEX


12,000


$7.50/$13.50


Jan 1 - Dec 31, 11Basis Swap

Credit Suisse

PG&E Citygate


12,000


$0.03


Jan 1 - Dec 31, 11Basis Swap

Credit Suisse

PG&E Citygate


16,000


$0.14


Jan 1 - Dec 31, 11Put

Credit Suisse

NYMEX


10,000


$6.00


Jan 1 - Dec 31, 11Put

Key Bank

NYMEX


14,000


$6.00


Jan 1 - Dec 31, 11Basis Swap

RBS

PG&E Citygate


11,000


$0.04


Jan 1 - Dec 31, 11Basis Swap

Scotia Capital

PG&E Citygate


6,624


$0.03


Jan 1 - Dec 31, 11Collar

Credit Suisse

NYMEX


15,500


$6.00/$9.10


Jan 1 - Dec 31, 12Put

RBS

NYMEX


7,800


$6.00


Jan 1 - Dec 31, 12


In
October 2009, we entered into a series of transactions whereby we reduced the ceilings on existing natural gas contracts covering 27,900 MMBtu per day from an average of $9.00 to
$7.00 for the period from January 2010 through December 2010 and on 12,000 MMBtu per day from $13.50 to $10.00 for the period from January 2011 through December 2011. We utilized the proceeds from
these transactions to partially fund the purchase of oil call spreads that increase the ceilings on existing oil contracts covering 3,500 Bbls per day from $73.00 to $85.00 and on 1,000 Bbls per day
from $72.80 to $95.00, each for the period from January 2010 to December 2010.

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

Oil

Type of Contract

Counterparty

Basis

Quantity
(Bbl/d)

Strike Price
($/Bbl)

TermCall Spread

Scotia Capital

NYMEX


1,000

$72.80/$95.00


Jan 1 - Dec 31, 10Call Spread

Credit Suisse

NYMEX


3,500

$73.00/$85.00


Jan 1 - Dec 31, 10


Natural Gas

Type of Contract

Counterparty

Basis

Quantity
(MMBtu/d)

Strike Price
($/MMBtu)

TermCall Spread

RBS

NYMEX


26,900

$9.00/$7.00


Jan 1 - Dec 31, 10Call Spread

RBS

NYMEX


1,000

$9.10/$7.00


Jan 1 - Dec 31, 10Call Spread

RBS

NYMEX


12,000

$13.50/$10.00


Jan 1 - Dec 31, 11


We
enter into derivative contracts, primarily collars, swaps and option contracts, to hedge future crude oil and natural gas production in order to mitigate the risk of market price
fluctuations. Most of our derivative contracts relate to changes in the market price relative to the applicable benchmark price; basis swap contracts relate to changes in the applicable differential.
The objective of our hedging activities and the use of derivative financial instruments is to achieve more predictable cash flows. Our hedging activities mitigate our exposure to price declines and
allow us more flexibility to continue to execute our capital plan even if prices decline. Our collar and swap contracts, however, prevent us from receiving the full advantage of increases in oil or
natural gas prices above the maximum fixed amount specified in the hedge agreement. Also, if production is less than the amount we have hedged and the price of oil or natural gas exceeds a fixed price
in a hedge contract, we will be required to make payments against which there are no offsetting sales of production. This could impact our liquidity and our ability to fund future capital
expenditures. 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

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with
our hedging activities, although we do not expect such losses to have a material effect on our liquidity or our ability to fund expected capital expenditures.

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

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

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

All
derivative instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying
market price at the determination date. Changes in the fair value of derivatives are recorded in commodity derivative gains (losses) on the consolidated statement of operations. As of
September 30, 2009, the fair value of our commodity derivatives was a net asset of $27.2 million.

Interest Rate Derivative Transactions

We are subject to interest rate risk with respect to amounts borrowed under our credit facilities because those amounts bear interest
at variable rates. As of November 2, 2009, there was approximately $548.8 million outstanding under those facilities. We entered into an interest rate swap transaction to limit our
exposure to changes in interest rates with respect to $500.0 million of variable rate borrowings through June 2010. In June 2009, we entered into a series of transactions to extend the term of
the interest rate swap to September 2011 and to reduce the rate from 5.32% to 4.035%. As a result, amounts borrowed up to $500.0 million were to effectively bear interest at a fixed rate of
approximately 8.0% until September 2011. In connection with the extension of the maturity on our second lien term loan facility to May 2014, we entered into a revised interest rate swap agreement in
October 2009 to extend the terms of the existing interest rate swap agreement from September 2011 to May 2014 and reduce the rate from 4.035% to a weighted average rate of 3.840%. As a result of the
revised agreement, $500 million of our variable rate debt will effectively bear interest at a fixed rate of approximately 7.8% until May 2014. Accordingly, we expect to be subject to interest
rate risk until that time only with respect to variable rate borrowings in excess of $500.0 million. As of November 2, 2009, there was approximately $48.8 million borrowed in
excess of the aforementioned $500.0 million. A 1.0% increase in interest rates on unhedged variable rate borrowings of $41.2 million at September 30,

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2009
would result in additional annualized interest expense of $0.4 million. As of September 30, 2009, the fair value of our interest rate derivatives was a liability of
$28.0 million.

See
notes to our consolidated financial statements for a discussion of our long-term debt as of September 30, 2009.

Item 4.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of Timothy Marquez, our Chief Executive Officer, and Timothy Ficker, our Chief Financial
Officer, evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2009. Based on the evaluation, those officers believe that:



Internal Control Over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during the quarterly period ended
September 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART IIOTHER INFORMATION

Item 1.    LEGAL PROCEEDINGS

Not Applicable

Item 1A.    RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in "Risk Factors" in
our Annual Report on Form 10-K for the year ended December 31, 2008, which could materially affect our business, financial condition and/or future results. The risks
described in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial
also may materially adversely affect our business, financial condition and/or operating results.

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

Not Applicable

Item 3.    DEFAULTS UPON SENIOR SECURITIES

Not Applicable

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

Not Applicable

Item 5.    OTHER INFORMATION

Not Applicable

Item 6.    EXHIBITS

Exhibit Number

Exhibit31.1

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

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

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


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Table of Contents

SIGNATURES

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

November 2,
2009

VENOCO, INC.By:

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

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


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