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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 June 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(State or other jurisdiction of
incorporation or organization)

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

80202-1370(Zip Code)


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

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

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

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

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

Large accelerated filer o

Accelerated filer ý

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

Smaller reporting company o


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

YES o    NO ý

As of June 30, 2009, there were 52,456,555 shares of the issuer's common stock, par value $0.01 per share, issued and outstanding.



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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report on Form 10-Q contains "forward-looking statements" as that term is defined in the Private Securities
Litigation Reform Act of 1995. The use of any statements containing the words "anticipate," "intend," "believe," "estimate," "project," "expect," "plan," "should" or similar expressions are intended
to identify such statements. Forward-looking statements included in this report relate to, among other things, expected future production, expenses and cash flows in 2009, the nature, timing and
results of capital expenditure projects, amounts of future capital expenditures, our future debt levels and liquidity, the future amount of the borrowing base and our 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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VENOCO, INC.  Form 10-Q for the Quarterly Period Ended June 30, 2009

TABLE OF CONTENTS



PART I.

FINANCIAL INFORMATIONItem 1.

Financial Statements (Unaudited)

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

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

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

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

5Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2008 and the Six Months Ended June 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

47PART II.

OTHER INFORMATIONItem 1.

Legal Proceedings

48Item 1A.

Risk Factors

48Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

48Item 3.

Defaults upon Senior Securities

48Item 4.

Submission of Matters to a Vote of Security Holders

48Item 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

June 30,
2009ASSETSCURRENT ASSETS:Cash and cash equivalents

$
191

$
1,584Accounts receivable, net of allowance for doubtful accounts of $750 and $900 at December 31, 2008 and June 30, 2009, respectively


41,306


31,291Inventories


12,361


4,446Prepaid expenses and other current assets


4,314


2,872Income taxes receivable


546


Commodity derivatives


57,247


48,542Total current assets


115,965


88,735PROPERTY, PLANT AND EQUIPMENT, AT COST:Oil and natural gas properties (full cost method, of which $30,228 and $55,341 for unproved properties were excluded from amortization at December 31,
2008 and June 30, 2009, respectively)


1,671,799


1,609,377Drilling equipment


14,460


14,460Other property and equipment


22,932


22,471Total property, plant and equipment


1,709,191


1,646,308Accumulated depletion, depreciation and amortization


(1,006,457
)

(1,048,347
)Net property, plant and equipment


702,734


597,961OTHER ASSETS:Commodity derivatives


35,314


29,340Deferred loan costs


7,458


6,190Other


2,783


3,164Total other assets


45,555


38,694TOTAL ASSETS

$
864,254

$
725,390LIABILITIES AND STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities

$
75,400

$
43,185Undistributed revenue payable


8,277


5,544Interest payable


5,325


1,701Income taxes payable





3,794Current maturities of long-term debt


2,598


Commodity and interest derivatives


21,284


37,912Total current liabilities


112,884


92,136LONG-TERM DEBT


797,670


694,532COMMODITY AND INTEREST DERIVATIVES


9,363


18,872ASSET RETIREMENT OBLIGATIONS


79,504


85,393Total liabilities


999,421


890,933COMMITMENTS AND CONTINGENCIESSTOCKHOLDERS' EQUITY:Common stock, $.01 par value (200,000,000 shares authorized; 51,548,990 and 52,456,555 shares issued and outstanding at December 31, 2008 and
June 30, 2009, respectively)


515


525Additional paid-in capital


319,336


322,020Retained earnings (accumulated deficit)


(453,594
)

(487,866
)Accumulated other comprehensive loss


(1,424
)

(222
)Total stockholders' equity


(135,167
)

(165,543
)TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
864,254

$
725,390


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
June 30,

Six Months Ended
June 30,2008

2009

2008

2009REVENUES:Oil and natural gas sales

$
167,132

$
62,011

$
303,797

$
119,442Other


915


803


1,700


1,688Total revenues


168,047


62,814


305,497


121,130EXPENSES:Oil and natural gas production


33,138


25,539


65,147


52,265Transportation expense


1,382


764


2,679


1,810Depletion, depreciation and amortization


29,870


20,608


61,116


43,291Accretion of asset retirement obligations


1,028


1,388


2,021


2,745General and administrative, net of amounts capitalized


12,165


8,559


21,231


16,557Total expenses


77,583


56,858


152,194


116,668Income (loss) from operations


90,464


5,956


153,303


4,462FINANCING COSTS AND OTHER:Interest expense, net


13,169


9,777


27,758


20,955Amortization of deferred loan costs


889


738


1,888


1,473Interest rate derivative losses (gains), net


(9,908
)

7,953


4,063


8,900Loss on extinguishment of debt





582





582Commodity derivative losses (gains), net


364,783


50,483


439,419


1,924Total financing costs and other


368,933


69,533


473,128


33,834Income (loss) before income taxes


(278,469
)

(63,577
)

(319,825
)

(29,372
)Income tax provision (benefit)


(105,900
)

(4,100
)

(121,800
)

4,900Net income (loss)

$
(172,569
)
$
(59,477
)
$
(198,025
)
$
(34,272
)Earnings per common share:Basic

$
(3.43
)
$
(1.17
)
$
(3.94
)
$
(0.68
)Diluted

$
(3.43
)
$
(1.17
)
$
(3.94
)
$
(0.68
)Weighted average common shares outstanding:Basic


50,347


50,781


50,287


50,742Diluted


50,347


50,781


50,287


50,742


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
June 30,

Six Months Ended
June 30,2008

2009

2008

2009Net income (loss)

$
(172,569
)
$
(59,477
)
$
(198,025
)
$
(34,272
)OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:Hedging activities:Reclassification adjustments for settled contracts


197


580


377


1,202Other comprehensive income (loss)


197


580


377


1,202Comprehensive income (loss)

$
(172,372
)
$
(58,897
)
$
(197,648
)
$
(33,070
)


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 contracts, net of tax














1,202


1,202Issuance of stock for cash upon exercise of options


20


1


173








174Issuance of restricted shares, net of cancellations


848


8


(8
)







Share-based payments








2,350








2,350Issuance of common stock pursuant to Employee Stock Purchase Plan


40


1


154








155Disgorgement of stock sale profits








15








15Net income (loss)











(34,272
)




(34,272
)BALANCE AT JUNE 30, 2009


52,457

$
525

$
322,020

$
(487,866
)
$
(222
)
$
(165,543
)


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)

Six Months Ended
June 30,2008

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

$
(198,025
)
$
(34,272
)Adjustments to reconcile net income (loss) to net cash provided by operating activities:Depletion, depreciation and amortization


61,116


43,291Accretion of abandonment liability


2,021


2,745Deferred income taxes (benefit)


(121,900
)

Share-based compensation


1,384


1,194Amortization of deferred loan costs


1,888


1,473Amortization of bond discounts and other non-cash interest


254


304Loss on extinguishment of debt





582Unrealized interest rate swap derivative losses (gains)


340


(170
)Unrealized commodity derivative losses (gains) and amortization of premiums and other comprehensive loss


383,914


50,200Changes in operating assets and liabilities:Accounts receivable


(17,130
)

10,029Inventories


1,653


(512
)Prepaid expenses and other current assets


1,861


1,512Income tax receivable/payable


100


4,340Other assets


3,075


(381
)Accounts payable and accrued liabilities


(1,658
)

(21,430
)Undistributed revenue payable


1,566


(3,633
)Net premiums paid on derivative contracts


(13,839
)

(8,012
)Net cash provided by operating activities


106,620


47,260CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for oil and natural gas properties


(155,447
)

(116,671
)Acquisitions of oil and natural gas properties


(4,624
)

(21,575
)Proceeds from sale of oil and natural gas properties





200,060Expenditures for other property and equipment


(2,481
)

(1,128
)Net cash (used in) provided by investing activities


(162,552
)

60,686CASH FLOWS FROM FINANCING ACTIVITIES:Proceeds from long-term debt


135,000


102,394Principal payments on long-term debt


(93,787
)

(209,016
)Payments for deferred loan costs


(811
)

(275
)Proceeds from derivative premium financing


7,817


Proceeds from Employee Stock Purchase Plan





155Proceeds from disgorgement of stock sale profits





15Proceeds from exercise of stock options


2,530


174Stock issuance costs


(5
)

Net cash (used in) provided by financing activities


50,744


(106,553
)Net increase (decrease) in cash and cash equivalents


(5,188
)

1,393Cash and cash equivalents, beginning of period


9,735


191Cash and cash equivalents, end of period

$
4,547

$
1,584Supplemental Disclosure of Cash Flow InformationCash paid for interest

$
28,795


24,301Cash paid for income taxes





560Supplemental Disclosure of Noncash ActivitiesAccrued capital expenditures at period end

$
29,474

$
15,028Increase (decrease) in accrued capital expenditures

$
(13,206
)
$
(15,175
)


See notes to condensed consolidated financial statements.

6

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES

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

Basis of PresentationThe unaudited condensed consolidated financial statements include the accounts of Venoco and its subsidiaries, all of which
are
wholly owned. The financial statements have been prepared in accordance with U.S. generally accepted accounting principles for interim financial reporting. All significant intercompany balances and
transactions have been eliminated in consolidation. In the opinion of management, all material adjustments considered necessary for a fair presentation of the Company's interim results have been
reflected. Venoco's Annual Report on Form 10-K for the year ended December 31, 2008 includes certain definitions and a summary of significant accounting policies and should
be read in conjunction with this report. The results for interim periods are not necessarily indicative of annual results.

In
the course of preparing the condensed consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets,
liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the
occurrence of future events and, accordingly, actual results could differ from amounts initially established. Significant areas requiring the use of assumptions, judgments and estimates include
(1) oil and gas reserves; (2) cash flow estimates used in ceiling tests of oil and natural gas properties; (3) depreciation, depletion and amortization; (4) asset
retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation
of commodity and interest 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 June 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 six months ended June 30, 2009, the tax expense recorded by the Company relates to federal AMT and state income taxes.

Earnings Per ShareStatement of Financial Accounting Standards No. 128,Earnings Per Share,
requires presentation of "basic" and "diluted" earnings per share. In June 2008, the FASB issued
FASB Staff Position No. EITF 03-6-1,Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating
Securities("FSP 03-6-1"). FSP 03-6-1 provides that unvested share-based payment awards that contain nonforfeitable rights to
dividends or dividend equivalents are participating securities and shall be included in the computation of EPS pursuant to the two-class method, as defined in SFAS 128. The
Company's unvested restricted stock awards contain certain nonforfeitable dividend rights. Accordingly, the Company adopted the FSP effective January 1, 2009.

7

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

Under
the two-class method, net income is reduced by dividends declared or paid in the current period. The remaining unallocated earnings are allocated between common stock
and participating securities (unvested restricted stock) in the same proportion that the securities share in dividends. Common stock and unvested restricted stock of the Company share equally in
distributed earnings. Basic EPS is calculated by dividing the earnings (distributed and undistributed) allocated to common stock by the weighted average shares outstanding. Diluted earnings per common
share is calculated by determining the most dilutive result between applying the two-class method or the treasury stock method. The Company's dilutive securities include
non-qualified stock options and unvested restricted stock, however these participating securities do not have a contractual obligation to share in the Company's losses. Therefore, in
periods of net loss, none of the net loss is allocated to the participating securities. As the Company reported net losses for all periods presented, the application of the two-class
method will not have an impact on the Company's earnings per share.

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

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2009

2008

2009Dilutive











Anti-dilutive


4,860,743


5,105,656


4,744,274


4,861,691


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

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2009

2008

2009Net income (loss)

$
(172,569
)
$
(59,477
)
$
(198,025
)
$
(34,272
)Allocation of net income to unvested restricted stock











Net income (loss) allocated to common stock

$
(172,569
)
$
(59,477
)
$
(198,025
)
$
(34,272
)Basic weighted average common shares outstanding


50,347


50,781


50,287


50,742Add: dilutive effect of stock options and non-vested restricted stock











Diluted weighted average common shares outstanding


50,347


50,781


50,287


50,742Basic earnings per common share

$
(3.43
)
$
(1.17
)
$
(3.94
)
$
(0.68
)Diluted earnings per common share

$
(3.43
)
$
(1.17
)
$
(3.94
)
$
(0.68
)




In March 2008, the FASB issued Statement No. 161,Disclosure about Derivative Instruments and Hedging
Activitiesan amendment to FASB Statement No. 133("SFAS 161"). SFAS 161 expands interim and annual disclosures about derivative and hedging
activities that are intended to better convey the

8

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

purpose
of derivative use and the risks managed. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008. The adoption of SFAS 161, effective
January 1, 2009, has not had an impact on the Company's consolidated financial statements, other than additional disclosures.

In
December 2007, the FASB issued Statement No. 141R,Business Combinations("SFAS 141R"). SFAS 141R establishes
principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling
interest in the acquiree. The statement also provides guidance for recognizing and measuring the goodwill acquired in business combinations and determines what information to disclose to enable users
of the financial statements to evaluate the nature and financial effects of the business combination. The statement applies prospectively to business combinations for which the acquisition date is on
or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Company adopted SFAS 141R, effective January 1, 2009, however the impact
on the Company's consolidated financial statements will be dependent upon the nature, terms and size of the acquisitions the Company consummates. The Company applied the provisions of SFAS 141R to the
Sacramento Basin Asset Acquisition which closed on June 30, 2009. See note 2 to the condensed consolidated financial statements for discussion of the impact of adoption.

In
February 2008, the FASB issued Staff Position FAS 157-2 ("FSP No. 157-2"), which delayed the effective date of SFAS 157 for nonfinancial
assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after
November 15, 2008. The Company's non-recurring nonfinancial assets and nonfinancial liabilities include those measured at fair value in impairment testing for unproved properties,
asset retirement obligations initially measured at fair value, and those measured at fair value in a business combination. Effective January 1, 2009, the Company adopted the provisions of
SFAS 157 relative to its non-recurring nonfinancial assets and nonfinancial liabilities. The adoption did not have a material impact on the Company's balance sheet, results of
operations, or cash flows.

In
May 2009, the FASB issued Statement No. 165,Subsequent Events("SFAS 165"), which established general standards of
accounting for and disclosure of events that occur after the balance sheet date but before the financial statements are issued. The statement defines the period after the balance sheet
date in which management should evaluate events or transactions that may require recognition or disclosure in the financial statements. Additionally, the statement sets forth the circumstances under
which an entity should recognize or disclose events occurring after the balance sheet date in the financial statements. The statement also identifies the disclosures required for subsequent events.
The statement is effective for all interim and annual periods ending after June 15, 2009. Adoption of the statement, effective June 30, 2009, did not result in any changes to the
Company's financial statements, other than additional disclosures. The Company has evaluated subsequent events through August 5, 2009, which is the date these financial statements were issued.

In
December 2008, the SEC published revised rules regarding oil and gas reserves reporting requirements. The objective of the rules are to provide readers of financial statements with
more meaningful and comprehensive understanding of oil and gas reserves. Key elements of the revised rules include a change in the pricing used to estimate reserves at period end, changes in certain
definitions, optional disclosure of probable and possible reserves, allowance of the use of new technologies in the

9

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VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

determination
of reserves and additional disclosure requirements. The rules also revise the prices used for reserves in determining depletion and the full cost ceiling test from a period end price to
a 12-month average price. The revised rules are effective for annual reports for fiscal years ending on or after December 31, 2009. Early adoption is not allowed. The Company is
currently assessing the impact that the adoption of the revised rules will have on its operating results, financial position, cash flows, oil and natural gas reserves and disclosures.

2. ACQUISITIONS AND SALES OF PROPERTIES

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.

Under
SFAS 141(R),Business Combinations, 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.
SFAS 157,Fair Value Measurements, defines fair value 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 under SFAS 157).
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, $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.

The
transaction closed on June 30, 2009, therefore, the revenues and earnings included in the statement of operations are immaterial to the Company's overall financial statement
presentation.

Hastings Complex Sale.In February 2009, the Company closed the sale of its principal interests in the Hastings complex ("Hastings
Sale") to a
subsidiary of Denbury Resources Inc. ("Denbury") for approximately $201.0 million, subject to certain post-closing adjustments. The Company used the proceeds from the sale to
repay the then full balance of the revolving credit facility of $187.1 million

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

2. ACQUISITIONS AND SALES OF PROPERTIES (Continued)

and
related interest of $0.5 million. In addition, the Company paid $5.5 million toward the principal balance on the second lien term loan. The Company did not recognize a gain for
financial reporting
purposes, but applied the proceeds from the Hastings Sale to reduce the capitalized cost of its oil and natural gas properties.

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

3. LONG-TERM DEBT

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

December 31,
2008

June 30,
2009Revolving credit agreement due March 2011

$
135,052

$
50,389Second lien term loan due September 2011


500,000


494,4858.75% senior notes due December 2011


149,590


149,658Financed derivative premiums due through 2011


15,626


Total long-term debt


800,268


694,532Less: current portion of long-term debt


(2,598
)

Long-term debt, net of current portion

$
797,670

$
694,532


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. The facility was amended on June 18, 2009 with the effect of
maintaining the borrowing base of $125.0 million and revising the interest rates applicable to borrowings. The facility is secured by a first priority lien on substantially all of the Company's
oil and natural gas properties and other assets, including the equity interests in all of the Company's subsidiaries, and is unconditionally guaranteed by each of the Company's operating subsidiaries
other than Ellwood Pipeline, Inc. The collateral also secures the Company's obligations to hedging counterparties that are also lenders, or affiliates of lenders, under the facility. Loans
designated as Base Rate Loans under the facility bear interest at a floating rate equal to (i) the greater of (x) the Bank of Montreal's announced base rate, (y) the overnight
federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.5%, plus (ii) an applicable margin ranging from 0.75% to 1.50%, based upon utilization. Loans designated as
LIBO Rate Loans under the facility bear interest at (i) LIBOR plus (ii) an applicable margin ranging from 2.25% to 3.00%, based upon utilization. A commitment fee of 0.50% per
annum is payable with respect to unused borrowing availability under the facility. The agreement governing the facility contains customary representations, warranties, events of default, indemnities
and covenants, including operational covenants that restrict the Company's

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

3. LONG-TERM DEBT (Continued)

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 August 5, 2009, the Company had effective available borrowing capacity of $67.1 million under the facility, net of the
outstanding balance of $50.4 million, $1.6 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. Principal on the facility is payable on
May 8, 2014. However, if the senior notes (see below) are still outstanding on September 20, 2011, principal on the term loan facility will be payable on that date.

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

Senior notes.In December 2004, the Company issued $150.0 million in 8.75% senior notes (the "senior notes") due December 2011.
Interest on
the senior notes is due each June 15 and December 15. The senior notes are senior obligations and contain covenants that, among other things, limit the Company's ability to make
investments, incur additional debt, issue preferred stock, pay dividends, repurchase its stock, create liens or sell assets. The senior notes were issued as unsecured obligations, but are currently
secured equally and ratably with the Company's second lien term loan facility.

The
Company was in compliance with all debt covenants at June 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

3. LONG-TERM DEBT (Continued)

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
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 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
June 30, 2009, the remaining unrealized derivative fair value loss of $1.1 million ($0.2 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 six
months.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

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
June 30, 2009, the balance of unamortized derivative premiums was $39.5 million, of which $12.0 million, $14.5 million and $13.0 million will be amortized in 2009
(remaining six months), 2010 and 2011, respectively.

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

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2009

2008

2009Realized commodity derivative (gains) losses

$
37,856

$
(16,288
)
$
56,119

$
(47,073
)Amortization of commodity derivative premiums


1,765


6,048


3,529


10,663Unrealized commodity derivative (gains) losses for changes in fair value:


325,162


60,723


379,771


38,334Commodity derivative (gains) losses

$
364,783

$
50,483

$
439,419

$
1,924


Crude Oil Agreements.As of June 30, 2009, the Company had entered into option, swap and collar agreements to receive average
minimum and
maximum New York Mercantile Exchange (NYMEX) West Texas Intermediate (WTI) prices as summarized below. Location and quality differentials attributable to the Company's properties are not included in
the following prices. The agreements provide for monthly settlement based on the differential between the agreement price and the actual NYMEX crude oil price.

MinimumMaximumAvg. PricesBarrels/day

Barrels/day

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


61,125

$
7.00


23,125

$
11.35January 1 - December 31, 2010


58,900

$
6.41


17,900

$
11.05January 1 - December 31, 2011


36,000

$
6.52


12,000

$
13.53


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

In July 2009, the Company entered into a series of transactions whereby it reduced the ceiling on
existing natural gas contracts covering 16,900 MMBtu per day from an average ceiling of $11.02 to $9.00 for the period from January 2010 through December 2010, sold natural gas calls covering 10,000
MMBtu per day at $9.00 for the period from January 2010 through December 2010, and utilized the proceeds from these transactions to partially fund the purchase of natural gas puts covering 7,800 MMBtu
per day at $6.00 and collars covering 15,500 MMBtu per day with limits of $6.00 and $9.10 for the period from January 2012 through December 2012.

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 receives 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
will effectively bear interest at a fixed rate of approximately 8.0% until September 2011. The Company has not designated 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
June 30,

Six months ended
June 30,2008

2009

2008

2009Realized interest rate derivative (gains) losses

$
3,307

$
5,130

$
3,724

$
9,070Unrealized interest rate derivative (gains) losses


(13,215
)

2,823


339


(170
)Interest rate derivative (gains) losses, net

$
(9,908
)
$
7,953

$
4,063

$
8,900


The
estimated fair values of derivatives included in the consolidated balance sheets at December 31, 2008 and June 30, 2009 are summarized below. The net
fair value of the Company's derivatives decreased by $40.8 million from a net asset of $61.9 million at December 31, 2008 to a net asset of $21.1 million at June 30,
2009 due to higher futures prices for oil, partially offset by declining 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

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

$
23,970

$
304Gas derivative contracts


33,277


48,23857,247


48,542Other AssetsCommodity derivatives:Oil derivative contracts


11,660


3,405Gas derivative contracts


23,654


25,93535,314


29,340Current LiabilitiesCommodity and interest derivatives:Oil derivative contracts


(1,672
)

(19,203
)Gas derivative contracts


(652
)

(1,996
)Interest rate derivative contracts


(18,960
)

(16,713
)(21,284
)

(37,912
)Commodity and interest rate derivatives:Oil derivative contracts





(7,612
)Gas derivative contracts


(180
)

Interest rate derivative contracts


(9,183
)

(11,260
)(9,363
)

(18,872
)Net derivative asset

$
61,914

$
21,098


5. FAIR VALUE MEASUREMENTS

Statement of Financial Accounting Standard No. 157 "Fair Value Measurements" (SFAS 157) defines fair value as the price that would be received in the sale of an asset or
paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would
use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or
generally unobservable. The Company classifies fair value balances based on the observability of those inputs. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to
measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to
unobservable inputs (level 3 measurement).

The
three levels of the fair value hierarchy defined by SFAS 157 are as follows:

Level 1Quoted
prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for
the asset or liability occur in

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

5. FAIR VALUE MEASUREMENTS (Continued)

sufficient
frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities.

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

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

As
required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their
placement within the fair value hierarchy levels. 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 June 30, 2009 (in thousands).

Level 1

Level 2

Level 3

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

$


$
77,882

$


$
77,882Commodity derivatives





(28,811
)




(28,811
)Interest rate swaps





(27,973
)




(27,973
)


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.

June 30, 2009Long Term Debt (in thousands)

Carrying
Amount

Estimated
Fair ValueSecond lien term loan

$
494,485

$375,8098.75% senior notes

$
149,658

$136,875


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, 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 six months ended June 30, 2008 and 2009 (in thousands):

Six Months
Ended
June 30, 2008

Six Months
Ended
June 30, 2009Asset retirement obligations at beginning of period

$
52,220

$
80,579Revisions of estimated liabilities


768


202Liabilities incurred/acquired


2,127


6,164Liabilities settled


(103
)

(229
)Disposition of properties





(2,993
)Accretion expense


2,021


2,745Asset retirement obligations at end of period


57,033


86,468Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)


(500
)

(1,075
)Long-term asset retirement obligations

$
56,533

$
85,393


7. CAPITAL STOCK

The Company has 61.3 million shares of common stock issued or reserved for issuance at June 30, 2009. At June 30, 2009, the Company has 52.5 million common
shares issued and outstanding, of which 1.6 million shares are restricted stock granted under the Company's 2005 stock incentive plan. At June 30, 2009, the Company had approximately
3.4 million options outstanding and 5.1 million shares

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

7. CAPITAL STOCK (Continued)

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
June 30, 2009, there are a total of 3,418,463 options outstanding with a weighted average exercise price of $9.08 ($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 the 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. The ESPP is
non-compensatory, as defined by SFAS 123R.

As
of June 30, 2009, there were a total of 1,647,955 shares of restricted stock outstanding under the Company's 2005 stock incentive plan, including 632,737 shares granted to its
CEO. The restricted shares generally have a requisite service period of four years. The grant date fair value of restricted stock subject to service conditions only is determined by the closing stock
price, as published by the New York Stock Exchange, on the day prior to the date of grant. The vesting of 943,291 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 June 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 six months ended June 30, 2009:

Options

Weighted
Average
Exercise
PriceOutstanding, start of period


3,504,263

$
9.16Granted





Exercised


(20,000
)
$
8.67Cancelled


(65,800
)
$
7.48Outstanding, end of period


3,418,463

$
9.08Exercisable, end of period


3,148,463

$
6.80


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

Shares

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


851,545

$
12.58Granted


890,376

$
2.86Vested


(50,733
)
$
13.11Forfeited


(43,233
)
$
11.32Non-vested, end of period


1,647,955

$
7.39


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

Three months
ended
June 30,

Six months
ended
June 30,2008

2009

2008

2009General and administrative expense

$
1,020

$
910

$
2,260

$
2,030Oil and natural gas production expense


160


190


260


320Total share-based compensation costs


1,180


1,100


2,520


2,350Less: share-based compensation costs capitalized


(583
)

(456
)

(1,136
)

(1,156
)Share-based compensation expensed

$
597

$
644

$
1,384

$
1,194


As
of June 30, 2009, there was $1.3 million of total unrecognized compensation cost related to stock options which is expected to be amortized over a weighted-average
period of 1.5 years and $7.5 million of total unrecognized compensation cost related to restricted stock which is expected to be amortized over a weighted-average period of
2.8 years.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(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 late 2009. The Company vigorously defended the actions, and will continue to do
so until they are resolved. Certain defendants have made claims for indemnity for events occurring prior to 1995, which the Company is disputing. The Company cannot predict the cost of these indemnity
claims at the present time.

One
of the Company's insurers currently is paying for the defense of these lawsuits under a reservation of its rights. Three other insurers that provided insurance coverage to the
Company (the "Declining Insurers") took the position that they were not required to provide coverage for losses arising out of, or to defend against, the lawsuits because of a pollution exclusion
contained in their policies. In February 2006, the Company filed a declaratory relief action against the Declining Insurers in Santa
Barbara County Superior Court seeking a determination that those insurers have a duty to defend the Company in the lawsuits. Two of the three Declining Insurers settled with the Company. The third
Declining Insurer disputed the Company's position and in November 2007 the Santa Barbara Court granted that insurer's motion for summary judgment, in part on the basis that the pollution exclusion
provision in the policy did not require that insurer to provide a defense for the Company. 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.

In
accordance with SFAS No. 5,Accounting for Contingencies, the Company has not accrued for a loss contingency relating to the
Beverly Hills litigation because the Company believes that, although unfavorable outcomes in the proceedings may be reasonably possible, the Company does not consider them to be probable or reasonably
estimable. If one or more of these matters are resolved in a manner

21

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Table of Contents

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

9. LITIGATION (Continued)

adverse
to the Company, and if insurance coverage is determined not to be applicable, their impact on the Company's results of operations, financial position and/or liquidity could be material.



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

10. GUARANTOR FINANCIAL INFORMATION

All subsidiaries of the Company other than Ellwood Pipeline Inc. ("Guarantors") have fully and unconditionally guaranteed, on a joint and several basis, the Company's obligations
under the senior notes. Ellwood Pipeline, Inc. is not a Guarantor (the "Non-Guarantor Subsidiary"). The condensed consolidating financial information for prior periods has been
revised to reflect the guarantor and non-guarantor status of the Company's subsidiaries as of June 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

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

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

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedASSETSCURRENT ASSETS:Cash and cash equivalents

$
1,583

$
1

$


$


$
1,584Accounts receivable


27,440


3,795


56





31,291Inventories


4,280


166








4,446Prepaid expenses and other current assets


2,872











2,872Commodity derivatives


48,542











48,542TOTAL CURRENT ASSETS


84,717


3,962


56





88,735PROPERTY, PLANT & EQUIPMENT, NET


672,933


(75,990
)

1,018





597,961COMMODITY DERIVATIVES


29,340











29,340INVESTMENTS IN AFFILIATES


504,389








(504,389
)

OTHER


8,860


494








9,354TOTAL ASSETS

$
1,300,239

$
(71,534
)
$
1,074

$
(504,389
)
$
725,390LIABILITIES AND STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities

$
38,644

$
4,541

$


$


$
43,185Undistributed revenue payable


5,509


35








5,544Interest payable


1,701











1,701Income taxes payable


3,794











3,794Commodity and interest derivatives


37,912











37,912TOTAL CURRENT LIABILITIES:


87,560


4,576








92,136LONG-TERM DEBT


694,532











694,532COMMODITY AND INTEREST DERIVATIVES


18,872











18,872ASSET RETIREMENT OBLIGATIONS


77,306


7,341


746





85,393INTERCOMPANY PAYABLES (RECEIVABLES)


587,512


(540,948
)

(46,564
)




TOTAL LIABILITIES


1,465,782


(529,031
)

(45,818
)




890,933TOTAL STOCKHOLDERS' EQUITY


(165,543
)

457,497


46,892


(504,389
)

(165,543
)TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
1,300,239

$
(71,534
)
$
1,074

$
(504,389
)
$
725,390


24

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Table of Contents

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

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
120,452

$
46,680

$


$


$
167,132Other


699


16


1,192


(992
)

915Total revenues


121,151


46,696


1,192


(992
)

168,047EXPENSES:Oil and natural gas production


19,468


13,070


600





33,138Transportation expense


2,297


4





(919
)

1,382Depletion, depreciation and amortization


23,715


6,132


23





29,870Accretion of asset retirement obligations


815


197


16





1,028General and administrative, net of amounts capitalized


11,239


926


73


(73
)

12,165Total expenses


57,534


20,329


712


(992
)

77,583Income (loss) from operations


63,617


26,367


480





90,464FINANCING COSTS AND OTHER:Interest expense, net


13,957


(6
)

(782
)




13,169Amortization of deferred loan costs


889











889Interest rate derivative losses (gains), net


(9,908
)










(9,908
)Commodity derivative losses (gains), net


364,783











364,783Total financing costs and other


369,721


(6
)

(782
)




368,933Equity in subsidiary income


17,180








(17,180
)

Income (loss) before income taxes


(288,924
)

26,373


1,262


(17,180
)

(278,469
)Income tax provision (benefit)


(116,355
)

9,980


475





(105,900
)Net income (loss)

$
(172,569
)
$
16,393

$
787

$
(17,180
)
$
(172,569
)


25

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Table of Contents

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

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
54,447

$
7,564

$


$


$
62,011Other


705


5


1,398


(1,305
)

803Total revenues


55,152


7,569


1,398


(1,305
)

62,814EXPENSES:Oil and natural gas production


21,452


3,502


585





25,539Transportation expense


1,964


24





(1,224
)

764Depletion, depreciation and amortization


18,831


1,754


23





20,608Accretion of asset retirement obligations


1,232


142


14





1,388General and administrative, net of amounts capitalized


7,901


658


81


(81
)

8,559Total expenses


51,380


6,080


703


(1,305
)

56,858Income (loss) from operations


3,772


1,489


695





5,956FINANCING COSTS AND OTHER:Interest expense, net


10,691


(1
)

(913
)




9,777Amortization of deferred loan costs


738











738Interest rate derivative losses (gains), net


7,953











7,953Loss on extinguishment of debt


582











582Commodity derivative losses (gains), net


50,483











50,483Total financing costs and other


70,447


(1
)

(913
)




69,533Equity in subsidiary income


1,921








(1,921
)

Income (loss) before income taxes


(64,754
)

1,490


1,608


(1,921
)

(63,577
)Income tax provision (benefit)


(5,277
)

566


611





(4,100
)Net income (loss)

$
(59,477
)
$
924

$
997

$
(1,921
)
$
(59,477
)


26

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Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS        SIX MONTHS ENDED JUNE 30, 2008 (Unaudited)        (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
222,455

$
81,342

$


$


$
303,797Other


1,382


25


2,403


(2,110
)

1,700Total revenues


223,837


81,367


2,403


(2,110
)

305,497EXPENSES:Oil and natural gas production


40,379


23,819


949





65,147Transportation expense


4,638


4





(1,963
)

2,679Depletion, depreciation and amortization


48,964


12,106


46





61,116Accretion of asset retirement obligations


1,599


390


32





2,021General and administrative, net of amounts capitalized


19,707


1,524


147


(147
)

21,231Total expenses


115,287


37,843


1,174


(2,110
)

152,194Income(loss) from operations


108,550


43,524


1,229





153,303FINANCING COSTS AND OTHER:Interest expense, net


29,304


(14
)

(1,532
)




27,758Amortization of deferred loan costs


1,888











1,888Interest rate derivative losses (gains), net


4,063











4,063Commodity derivative losses (gains), net


439,419











439,419Total financing costs and other


474,674


(14
)

(1,532
)




473,128Equity in subsidiary income


28,668








(28,668
)

Income (loss) before income taxes


(337,456
)

43,538


2,761


(28,668
)

(319,825
)Income tax provision (benefit)


(139,431
)

16,580


1,051





(121,800
)Net income (loss)

$
(198,025
)
$
26,958

$
1,710

$
(28,668
)
$
(198,025
)


27

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Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS        SIX MONTHS ENDED JUNE 30, 2009 (Unaudited)        (in thousands)

Venoco, Inc.

Guarantor
Subsidiaries

Non-Guarantor
Subsidiary

Eliminations

ConsolidatedREVENUES:Oil and natural gas sales

$
102,668

$
16,774

$


$


$
119,442Other


1,468


27


2,809


(2,616
)

1,688Total revenues


104,136


16,801


2,809


(2,616
)

121,130EXPENSES:Oil and natural gas production


42,878


8,329


1,058





52,265Transportation expense


4,226


39





(2,455
)

1,810Depletion, depreciation and amortization


38,744


4,500


47





43,291Accretion of asset retirement obligations


2,417


301


27





2,745General and administrative, net of amounts capitalized


15,332


1,225


161


(161
)

16,557Total expenses


103,597


14,394


1,293


(2,616
)

116,668Income (loss) from operations


539


2,407


1,516





4,462FINANCING COSTS AND OTHER:Interest expense, net


22,751


(4
)

(1,792
)




20,955Amortization of deferred loan costs


1,473











1,473Interest rate derivative losses (gains), net


8,900











8,900Loss on extinguishment of debt


582











582Commodity derivative losses (gains), net


1,924











1,924Total financing costs and other


35,630


(4
)

(1,792
)




33,834Equity in subsidiary income


3,546








(3,546
)Income (loss) before income taxes


(31,545
)

2,411


3,308


(3,546
)

(29,372
)Income tax provision (benefit)


2,727


916


1,257





4,900Net income (loss)

$
(34,272
)
$
1,495

$
2,051

$
(3,546
)
$
(34,272
)


28

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Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS        SIX MONTHS ENDED JUNE 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

$
67,139

$
37,834

$
1,647

$


$
106,620CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for oil and natural gas properties


(128,654
)

(26,806
)

13





(155,447
)Acquisitions of oil and natural gas properties


(2,589
)

(2,035
)







(4,624
)Expenditures for property and equipment and other


(2,395
)

(86
)







(2,481
)Net cash provided by (used in) investing activities


(133,638
)

(28,927
)

13





(162,552
)CASH FLOWS FROM FINANCING ACTIVITIES:Net proceeds from (repayments of) intercompany borrowings


11,539


(9,879
)

(1,660
)




Proceeds from long-term debt


135,000











135,000Principal payments on long-term debt


(93,787
)










(93,787
)Payments for deferred loan costs


(811
)










(811
)Proceeds from derivative premium financing


7,817











7,817Proceeds from exercise of stock options


2,530











2,530Stock issuance costs


(5
)










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


62,283


(9,879
)

(1,660
)




50,744Net increase (decrease) in cash and cash equivalents


(4,216
)

(972
)







(5,188
)Cash and cash equivalents, beginning of period


8,762


973








9,735Cash and cash equivalents, end of period

$
4,546

$
1

$


$


$
4,547


29

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Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS        SIX MONTHS ENDED JUNE 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

$
29,005

$
14,929

$
3,326

$


$
47,260CASH FLOWS FROM INVESTING ACTIVITIES:Expenditures for oil and natural gas properties


(107,207
)

(9,464
)







(116,671
)Acquisitions of oil and natural gas properties


(21,575
)










(21,575
)Proceeds from sale of oil and natural gas properties





200,060








200,060Expenditures for property and equipment and other


(1,655
)

527








(1,128
)Net cash provided by (used in) investing activities


(130,437
)

191,123








60,686CASH FLOWS FROM FINANCING ACTIVITIES:Net proceeds from (repayments of) intercompany borrowings


209,378


(206,052
)

(3,326
)




Proceeds from long-term debt


102,394











102,394Principal payments on long-term debt


(209,016
)










(209,016
)Payments for deferred loan costs


(275
)










(275
)Proceeds from Employee Stock Purchase Plan


155











155Proceeds from disgorgement of stock sale profits


15











15Proceeds from exercise of stock options


174











174Net cash provided by (used in) financing activities


102,825


(206,052
)

(3,326
)




(106,553
)Net increase (decrease) in cash and cash equivalents


1,393











1,393Cash and cash equivalents, beginning of period


190


1








191Cash and cash equivalents, end of period

$
1,583

$
1

$


$


$
1,584


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 20,434 BOE/d in the second quarter of 2009, compared to 21,033 BOE/d in the second quarter of 2008 and 21,728 BOE/d in the first quarter of 2009. Excluding
production from the Hastings complex, which we sold on February 2, 2009 (see "Acquisitions and Divestitures"), our average net production was 20,434 BOE/d in the second quarter of
2009, compared to 18,289 BOE/d in second quarter of 2008 and 20,818 BOE/d in the first 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 $150.0 million, of which approximately $102.7 million was expended in the first six months
of 2009. We expect to spend approximately 54% of the budgeted amount on projects in the Sacramento Basin, 28% in Southern California, 6% in Texas and 12% for exploration projects in a variety of
areas. We have entered into hedging arrangements that provide price floors on approximately 95% of our revised annual 2009 production guidance and a significant portion of our expected production in
2010 and 2011. The price floors are intended to ensure a minimum revenue stream to support an active capital expenditure program and satisfy our other obligations. While we expect capital spending in
the second half of 2009 to equal approximately one half of the capital expenditures in the first six months of 2009, the aggregate levels of capital expenditures for the remainder of 2009, and the
allocation of those expenditures, are dependent on a variety of factors, including the availability of capital resources to fund the expenditures and changes in our business assessments as to where
our capital can be most profitably employed. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from our estimates. The following
summarizes certain significant aspects of our 2009 capital spending program:

Southern CaliforniaExploitation and Development

Our primary focus in Southern California in 2009 is on development activities in the West Montalvo field, where we are continuing a
workover, recompletion and return to production program that we began when we acquired the field in May 2007. During the first six months of 2009, we

31

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Table of Contents

completed
two wells that were spud during the fourth quarter of 2008 and performed five workovers and recompletions. We plan to drill two additional wells in the West Montalvo field later in 2009.

In
the Sockeye field, we continue to optimize our waterflood program from platform Gail. During the first six months of the year, we drilled a dual completion well that produces from the
Monterey formation and expands the waterflood by injecting into the Upper Topanga formation.

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 before early 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 will become 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 entered the
year with six drilling rigs and seven workover/completion rigs but were operating a three rig drilling program by the end of February. We recently dropped another drilling rig and expect our rig
utilization for the remainder of 2009 to average 1-2 rigs. Over the course of the second quarter we reduced our workover/completion rig count from seven to three. We expect to drill approximately 60
new wells and perform more than 150 workovers and recompletions in the basin during the year. During the first six months of 2009, we spud 45 wells, completed 40 (including wells spud in 2008), and
performed 113 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 in 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 simulations 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 intend to utilize the knowledge
and experience we gained operating the Hastings complex to redevelop 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,

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we
are in the process of unitizing the Manvel field and believe it is a solid candidate for a CO2 flood operation.

Our
2009 capital expenditure budget originally included capital for up to three new development wells and approximately seven workovers and recompletions in Texas. We have elected to
defer the drilling of two joint-interest wells planned for 2009 in order to focus on workover opportunities. During the first six months of 2009, we performed four workovers at the Manvel field and
nine workovers at our other Texas properties. We anticipate similar levels of workover activity during the second half of the year.
We plan to drill one new well this year in Texas, a 100% working interest well in the South Liberty field that we expect to spud during the third quarter.

Exploration Activities

During the first six months of the year we spud two exploration wells in Washington, neither of which found commercial hydrocarbons.
Both wells have been plugged and abandoned. The drilling results confirm that the necessary elements exist for hydrocarbon accumulation in this area and our geoscientists are incorporating the data
from these wells into an updated geologic model.

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
$201.0 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.

For
illustrative purposes, we have presented below historical production volumes and the results of operations attributable to the Hastings complex for the three and six month periods
ended June 30, 2008 and the six month period ended June 30, 2009 (which includes only January for the 2009 period).

Three Months Ended June 30,

Six Months
Ended June 30,2008

2008

2009Production Volume:Oil (MBbls)


247


483


81Natural gas (MMcf)


19


40


4Statement of Operations (in thousands):Oil sales

$
30,799

$
54,354

$
3,275Gas sales


205


379


19Lease operating expenses


6,752


14,372


1,636Production and property taxes


1,628


3,097


332Lease Operating Expenses per BOE

$
27.40

$
29.33

$
19.95


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

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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 addition, as a result of declines in commodity prices as well as the deterioration in the overall economy in
2008, we significantly reduced our capital expenditures planned for 2009 as compared to our actual capital expenditures incurred in 2008. In order to reduce the variability of the prices we receive
for our production and provide a minimum revenue stream, we employ a hedging strategy. As of June 30, 2009, we had hedge contract floors covering approximately 95% of our revised 2009
production guidance and a significant portion of our expected production in 2010 and 2011. All of our derivatives counterparties are members, or affiliates of members, of our revolving credit facility
syndicate. See "Quantitative and Qualitative Disclosures About Market RiskCommodity Derivative Transactions" for further details concerning our hedging activities.

Expected Production.We expect that the execution of our capital expenditure program in 2009 will result in average daily production
volumes in 2009
of approximately 20,250 BOE/d compared to 19,088 BOE/d for 2008, pro forma for the Hastings sale. We expect our Southern California properties, which produced 3.0 MMBOE during 2008 (of which 94% was
oil), to exhibit modest production growth as compared to 2008. In particular, we expect the drilling and workover/recompletion programs at the West Montalvo field to result in production increases in
2009. In the Sacramento Basin, we intend to continue our multi-year drilling program and plan to drill approximately 60 new wells and perform more than 150 workovers and recompletions.
Despite reducing the number of rigs active in the basin over the course of the year, we expect average daily production in the basin to increase slightly in 2009 relative to 2008. At the Manvel field,
which we acquired in April 2007, we are continuing a redevelopment program by upgrading our fluid handling and injection capacity and plan to perform approximately five workovers and recompletions. We
expect average daily production from our Texas properties to increase slightly in 2009 relative to 2008, pro forma for the sale of Hastings. 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
$15.04 per BOE for the first six months of 2008 to $12.12 per BOE in the first six months of 2009. We expect our production expenses to decrease on a BOE basis for 2009 relative to 2008, primarily as
a result of the sale of our principal interests in the Hastings complex, where our per BOE costs were relatively high. We expect production/property taxes to remain relatively flat on a per BOE basis
in 2009. 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 $4.55 per BOE for the first six months of 2008
(excluding
charges under SFAS 123R of $0.29 per BOE and non-recurring charges of $0.70 per BOE relating to the termination of a planned master limited partnership ("MLP") offering), to $4.11
per BOE (excluding SFAS 123R charges of $0.23 per BOE) in the first six months of 2009. Excluding SFAS 123R charges, on a per BOE basis, we expect our 2009 G&A costs to be similar
to our full year 2008 costs of $4.79 per BOE. As with production expenses, our expectations with respect to G&A costs are subject to numerous risks and uncertainties.

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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 quarter 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
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 six months ended June 30, 2008 and 2009.

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2009

2008

2009Production Volume:Oil (MBbls)(1)


975


848


1,959


1,782Natural gas (MMcf)


5,634


6,069


11,210


12,198MBOE


1,914


1,860


3,827


3,815Daily Average Production Volume:Oil (Bbls/d)


10,714


9,319


10,764


9,845Natural gas (Mcf/d)


61,912


66,692


61,593


67,392BOE/d


21,033


20,434


21,030


21,077Oil Price per Bbl Produced (in dollars):Realized price

$
114.37

$
49.67

$
102.55

$
41.67Realized commodity derivative gain (loss)


(38.44
)

(0.30
)

(28.42
)

4.88Net realized price

$
75.93

$
49.37

$
74.13

$
46.55Natural Gas Price per Mcf (in dollars):Realized price

$
10.39

$
3.20

$
9.14

$
3.81Realized commodity derivative gain (loss)


(0.07
)

3.16


(0.04
)

2.51Net realized price

$
10.32

$
6.36

$
9.10

$
6.32Expense per BOE:Lease operating expenses(2)

$
15.40

$
12.46

$
15.04

$
12.12Production and property taxes(2)


1.91


1.27


1.98


1.58Transportation expenses


0.72


0.41


0.70


0.47Depreciation, depletion and amortization


15.61


11.08


15.97


11.35General and administrative expense(3)


6.36


4.60


5.55


4.34Interest expense


6.88


5.26


7.25


5.49


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

Oil and Natural Gas Sales.Oil and natural gas sales decreased $105.1 million (63%) to $62.0 million for the quarter ended
June 30, 2009 from $167.1 million for the same period in 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 $66.0 million (61%) in the second quarter of 2009 to $42.6 million compared to $108.6 million in the second quarter of 2008. Oil production
decreased by 13%, with production of 848 MBbl in the second quarter of 2009 compared to 975 MBbl in the second quarter of 2008. The production decrease was primarily due to the sale of the Hastings
complex in early February 2009. Excluding Hastings, production increased 120 MBbl (16%) from 728 MBbl in the second quarter of 2008 to 848 MBbl in the second quarter of 2009. The increase is primarily
due to increased production at the West Montalvo and Sockeye fields as a result of drilling and recompletion activities in the latter half of 2008 and the first six months of 2009. Additionally,
scheduled downtime in the Sockeye and South Ellwood fields in April and June 2008 reduced production in the second quarter of 2008 relative to the second quarter of 2009. Our average realized price
for oil decreased $64.70 (57%) to $49.67 per Bbl for the period.

Natural
gas sales decreased $39.2 million (67%) in the second quarter of 2009 to $19.4 million compared to $58.6 million in the second quarter of 2008. Natural gas
production increased 8%, with production of 6,069 MMcf in the second quarter of 2009 compared to 5,634 MMcf in the second quarter of 2008. The increase was due primarily to drilling, recompletion and
hydraulic fracturing activities in the Sacramento Basin. The increase was partially offset by a shut-in of production from a portion of our Grimes field due to pipeline repairs that
occurred from April 21 through June 5, 2009. Our average realized price for natural gas decreased $7.19 (69%) to $3.20 per Mcf for the period.

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

Production Expenses.Production expenses, which consist of lease operating expenses ("LOE") and production/property taxes, decreased
$7.6 million (23%) to $25.5 million in the second quarter of 2009 from $33.1 million in the second 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 $12.46 per BOE in the second quarter of 2009 from $15.40 per BOE in the same period in 2008.
Excluding Hastings, LOE per BOE decreased $1.20 from $13.66 per BOE in the second quarter of 2008 to $12.46 per BOE in the second quarter of 2009. The decrease is partially due to the increased
proportion of Sacramento Basin natural gas production during the second quarter of 2009, which has lower operating costs than oil production. We have also realized lower operating costs at our
non-operated Dos Cuadros properties in the second quarter of 2009 compared with the same period in 2008. Additionally, we incurred higher costs in the second quarter of 2008 related to
certain maintenance costs associated with the scheduled downtime at South Ellwood. We also continue to pursue price/cost reductions from external contractors and suppliers.

Transportation Expenses.Transportation expenses decreased $0.6 million (45%) to $0.8 million in the second quarter of 2009
from
$1.4 million in the second quarter of 2008. On a per BOE basis, transportation expenses decreased $0.31 per BOE, from $0.72 per BOE in the second quarter of 2008 to $0.41 per BOE in the second
quarter of 2009. The decrease is primarily due to demurrage reimbursements received in 2009 related to the barge used to transport our South Ellwood field oil.

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Depletion, Depreciation and Amortization (DD&A).DD&A expense decreased $9.3 million (31%) to $20.6 million in the
second quarter of
2009 from $29.9 million in the second quarter of 2008. DD&A expense decreased $4.53 per BOE, from $15.61 per BOE in the second quarter of 2008 to $11.08 per BOE in the second quarter of 2009.
The decrease is due to a reduced amortizable base as a result of the full cost ceiling write down recorded at December 31, 2008 and the application of proceeds from the sale of the Hastings
complex in February 2009 to reduce the full cost pool.

Accretion of Abandonment Liability.Accretion expense increased $0.4 million (35%) to $1.4 million in the second quarter of
2009 from
$1.0 million in the second 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 2008 and the first half of 2009.

General and Administrative (G&A).G&A expense decreased $3.6 million (30%) to $8.6 million in the second quarter of
2009 from
$12.2 million in the second quarter of 2008. The decrease 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. 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 SFAS 123R compensation expense charged to G&A remained relatively constant at $0.4 million in 2008
and $0.5 million in 2009. Excluding the effect of the non-cash SFAS 123R compensation expense and MLP write-off charges, G&A expense decreased $0.36 from $4.72
per BOE in the second quarter of 2008 to $4.36 per BOE in the second quarter of 2009.

Interest Expense, Net.Interest expense, net of interest income, decreased $3.4 million (26%) from $13.2 million in the
second quarter
of 2008 to $9.8 million in the second quarter of 2009. The decrease was primarily the result of a reduction in our average debt outstanding and lower interest rates realized during the second
quarter of 2009.

Amortization of Deferred Loan Costs.Amortization of deferred loan costs decreased $0.2 million, from $0.9 million in the
second
quarter of 2008 to $0.7 million in the second quarter of 2009. The decrease was primarily due to the amendment to the revolving credit facility in May 2008 which extended the maturity date of
the facility.

Interest Rate Derivative (Gains) Losses, Net.Changes in the fair value of our interest rate swap derivative instruments resulted in
unrealized
losses of $2.8 million in the second quarter of 2009 and unrealized gains of $13.2 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
$5.1 million in the second quarter of 2009 compared to realized losses of $3.3 million in the second quarter of 2008.

Loss on Extinguishment of Debt.We recognized a loss on extinguishment of debt in the second quarter of 2009 of $0.6 million
related to
repayment of the financed derivative premiums balance in June 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):

Three Months Ended
June 30,2008

2009Realized commodity derivative (gains) losses

$
37,856

$
(16,288
)Amortization of commodity derivative premiums


1,765


6,048Unrealized commodity derivative (gains) losses for changes in fair value


325,162


60,723Commodity derivative (gains) losses

$
364,783

$
50,483


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 second quarter of 2009 reflect the settlement of contracts at prices below the relevant strike prices, while the realized derivative loss in the second
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
June 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 second quarter of 2009 of $4.1 million
reflects the reduction of the estimated federal AMT payable based on current earnings. The net loss for the second quarter of 2008 resulted in an income tax benefit of $105.9 million.

Net Income (Loss).Net loss for the second quarter of 2009 was $59.5 million compared to net loss of $172.6 million for the
same period
in 2008. The change between periods is the result of the items discussed above.

Comparison of Six Months Ended June 30, 2009 to Six Months Ended June 30, 2008

Oil and Natural Gas Sales.Oil and natural gas sales decreased $184.4 million (61%) to $119.4 million for the six months
ended
June 30, 2009 from $303.8 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 $128.3 million (64%) for the first half of 2009 to $73.0 million compared to $201.3 million in the first half of 2008. Oil production
decreased by 9%, with production of 1,782 MBbl in the first half of 2009 compared to 1,959 MBbl in the first half of 2008. The production decrease was primarily due to the sale of the Hastings complex
in early February 2009. Excluding Hastings, production increased 225 MBbl (15%) from 1,476 MBbl in the first half of 2008 to 1,701 MBbl in the first half 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 six months of 2009. Additionally, scheduled
downtime in the Sockeye and South Ellwood fields in April and June 2008 reduced production in the first half of 2008 relative to the first half of 2009. Our average realized price for oil decreased
$60.88 (59%) to $41.67 per Bbl for the period.

Natural
gas sales decreased $56.1 million (55%) in the first half of 2009 to $46.4 million compared to $102.5 million in the first half of 2008. Natural gas
production increased 9%, with production of 12,198 MMcf in the first half of 2009 compared to 11,210 MMcf in the first half of 2008. The increase

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was
due primarily to drilling, recompletion and hydraulic fracturing activities in the Sacramento Basin. Our average realized price for natural gas decreased $5.33 (58%) to $3.81 per Mcf for the
period.

Other Revenues.Other revenue remained constant for both the first half of 2009 and 2008 at $1.7 million.

Production Expenses.Production expenses, which consist of lease operating expenses ("LOE") and production/property taxes, decreased
$12.8 million (20%) to $52.3 million in the first half of 2009 from $65.1 million in the first half 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 $12.12 per BOE in the first half of 2009 from $15.04 per BOE in the same period in 2008.
Excluding Hastings, LOE per BOE decreased $1.00 from $12.94 per BOE in the first half of 2008 to $11.94 per BOE in the first half of 2009. The decrease is partially due to the increased proportion of
Sacramento Basin natural gas production during the first half of 2009, which has lower operating costs than oil production. We have also realized lower operating costs at our non-operated
Dos Cuadros properties in the first half of 2009 compared with the same period in 2008. Additionally, we incurred higher costs in the first half of 2008 related to certain maintenance costs associated
with the scheduled downtime at South Ellwood. We also continue to pursue price/cost reductions from external contractors and suppliers.

Transportation Expenses.Transportation expenses decreased $0.9 million (32%) to $1.8 million in the first
half of 2009 from $2.7 million in the first half of 2008. On a per BOE basis, transportation expenses decreased $0.23 per BOE, from $0.70 per BOE in the first half of 2008 to $0.47 per BOE in
the first half of 2009. The decrease is primarily due to demurrage reimbursements received in 2009 related to the barge used to transport our South Ellwood oil.

Depletion, Depreciation and Amortization (DD&A).DD&A expense decreased $17.8 million (29%) to $43.3 million in the
first half of 2009
from $61.1 million in the first half of 2008. DD&A expense decreased $4.62 per BOE, from $15.97 per BOE in the first half of 2008 to $11.35 per BOE in the first half 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.

Accretion of Abandonment Liability.Accretion expense increased $0.7 million (36%) to $2.7 million in the first half of 2009
from
$2.0 million in the first half 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 half of 2009.

General and Administrative (G&A).G&A expense decreased $4.6 million (22%) to $16.6 million in the first half of 2009
from
$21.2 million in the first half of 2008. The decrease 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. 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 SFAS 123R compensation expense charged to G&A decreased $0.2 million (22%) from $1.1 million in 2008 to
$0.9 million in 2009, primarily as a result of certain awards which fully vested during the first quarter of 2009. Excluding the effect of the non-cash SFAS 123R compensation
expense charges and MLP write-off charges, G&A expense decreased $0.44 from $4.55 per BOE in the first half of 2008 to $4.11 per BOE in the first half of 2009.

Interest Expense, Net.Interest expense, net of interest income, decreased $6.8 million (25%) from $27.8 million in the first
half of
2008 to $21.0 million in the first half of 2009. The decrease was

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primarily
the result of a reduction in our average debt outstanding and lower interest rates realized during the first half of 2009.

Amortization of Deferred Loan Costs.Amortization of deferred loan costs decreased $0.4 million, from $1.9 million in the
first half of
2008 to $1.5 million in the first half 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 half of 2009 and unrealized losses 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 $9.1 million in the
first half of 2009 compared to realized losses of $3.7 million in the first half of 2008.

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

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

Six Months Ended
June 30,2008

2009Realized commodity derivative (gains) losses

$
56,119

$
(47,073
)Amortization of commodity derivative premiums


3,529


10,663Unrealized commodity derivative (gains) losses for changes in fair value


379,771


38,334Commodity derivative (gains) losses

$
439,419

$
1,924


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
June 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 expense for the first six months of 2009 of $4.9 million
relates to federal AMT and state income taxes based on current earnings. The net loss for the first six months of 2008 resulted in an income tax benefit of $121.8 million.

Net Income (Loss).Net loss for the first six months of 2009 was $34.3 million compared to net loss of $198.0 million for the
same
period in 2008. The change between periods is the result of the items discussed above.

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Table of Contents

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

Six Months Ended
June 30,2008

2009(in thousands)Cash provided by operating activities

$
106,620

$
47,260Cash (used in) provided by investing activities


(162,552
)

60,686Cash (used in) provided by financing activities


50,744


(106,553
)


Net
cash provided by operating activities was $47.3 million in the first six months of 2009 compared with $106.6 million in the first six months of 2008. Cash flows from
operating activities in the first six months of 2009 as compared to the first six months of 2008 were unfavorably impacted by significant decreases in commodity prices.

Net
cash provided by investing activities was $60.7 million in the first six months of 2009 compared with $162.6 million used in the first six months of 2008. The primary
investing activities in the first six months of 2009 were receipt of $200.1 million in cash proceeds from the sale of the Hastings complex offset by $116.9 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 six months of 2008 include $161.2 million in capital expenditures on oil and gas properties.

Net
cash used in financing activities was $106.6 million in the first six months of 2009 compared to $50.7 million provided by financing activities in the first six months
of 2008. The primary financing activities in the first six months of 2009 were $84.7 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 paid with proceeds from the Hastings sale. Additionally, we paid approximately $15.2 million in June 2009 to settle financed derivative
premiums. Financing activities in the first six months of 2008 included $43.0 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 $150.0 million in 2009. We intend to finance these capital
expenditures primarily through cash flow from operations. We do not currently expect to borrow any significant additional amounts under the revolving credit facility during the remainder of 2009.
Although we consequently expect to maintain additional borrowing capacity under the facility, 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. Uncertainties
relating to our capital resources and requirements in 2009 include the possibility that one or more of the counterparties to our hedging arrangements fails to perform under the contracts, 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.

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

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

The
revolving credit facility has a total capacity of $300.0 million, but is limited by a borrowing base 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 $50.4 million through August 5, 2009, to finance certain derivative
premiums and fund the Sacramento Basin asset acquisition and 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.

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Table of Contents

Loans under the term loan facility designated as "Base Rate Loans" bear interest at a floating rate equal to (i) the greater of the overnight federal funds
rate plus 0.50% and the administrative agent's announced base rate, plus (ii) 3.00%. Loans designated as "LIBO Rate Loans" bear interest at LIBOR plus 4.00%. We have entered into interest rate
swaps pursuant to which amounts borrowed under the term loan agreement will effectively bear interest at a fixed rate of approximately 8.0% until September 2011. See "Quantitative and Qualitative
Disclosures About Market RiskInterest Rate Derivative Transactions."

Senior Notes.We issued $150.0 million of our senior notes in December 2004. The notes bear interest at 8.75% per year and will
mature on
December 15, 2011. We may redeem the notes at a redemption price currently equal to 104.375% of the principal amount and declining to 100% of the principal amount by December 15, 2010.
Upon the occurrence of a change of control of our company, each holder of the notes may require us to repurchase all or a portion of its notes for cash at a price equal to 101% of the aggregate
principal amount of those notes, plus any accrued and unpaid interest. The indenture governing the notes also contains operational covenants that, among other things, limit our ability to make
investments, incur additional indebtedness or create liens on our assets. The notes are secured with the second lien term loan on an equal and ratable basis.

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

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

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Table of Contents

Item 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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 June 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 June 30, 2009 for production:July 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 June 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 June 30, 2009 for production:July 1 - December 31, 2009


61,125

$
7.00


23,125

$
11.35January 1 - December 31, 2010


58,900

$
6.41


17,900

$
11.05January 1 - December 31, 2011


36,000

$
6.52


12,000

$
13.53


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Table of Contents

Portfolio of Derivative Transactions

Our portfolio of commodity derivative transactions as of June 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


Jul 1 - Dec 31, 09Swap

Fortis Bank

NYMEX


2,000

$
67.22


Jul 1 - Dec 31, 09Swap

Bank of Montreal

NYMEX


3,000

$
58.14


Jul 1 - Dec 31, 09Collar

Bank of Montreal

NYMEX


750

$
60.00/$82.75


Jul 1 - Dec 31, 09Put

Bank of Montreal

NYMEX


2,000

$
40.00


Jul 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


Jul 1 - Dec 31, 09Basis Swap

Bank of Montreal

PG&E Citygate


7,500

$
0.11


Jul 1 - Dec 31, 09Collar

Bank of Montreal

NYMEX


1,125

$
8.00/$12.00


Jul 1 - Dec 31, 09Collar

Bank of Montreal

NYMEX


4,000

$
7.30/$9.85


Jul 1 - Dec 31, 09Collar

Bank of Montreal

NYMEX


7,000

$
7.50/$12.75


Jul 1 - Dec 31, 09Collar

Credit Suisse

NYMEX


8,500

$
7.50/$11.15


Jul 1 - Dec 31, 09Put

Credit Suisse

NYMEX


10,000

$
8.50


Jul 1 - Dec 31, 09Put

Credit Suisse

NYMEX


28,000

$
6.00


Jul 1 - Dec 31, 09Basis Swap

Credit Suisse

PG&E Citygate


19,625

$
0.00


Jul 1 - Dec 31, 09Swap

Credit Suisse

NYMEX


1,250

$
8.00


Jul 1 - Dec 31, 09Collar

Credit Suisse

NYMEX


1,250

$
7.25/$11.30


Jul 1 - Dec 31, 09Basis Swap

Bank of Montreal

PG&E Citygate


6,475

$
0.14


Jul 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, 10Collar

Credit Suisse

NYMEX


12,000

$
7.50/$13.50


Jan 1 - Dec 31, 11Basis Swap

Credit Suisse

PG&E Citygate


12,000

$
0.03


Jan 1 - Dec 31, 11Put

Credit Suisse

NYMEX


10,000

$
6.00


Jan 1 - Dec 31, 11Put

Key Bank

NYMEX


14,000

$
6.00


Jan 1 - Dec 31, 11Basis Swap

Scotia Capital

PG&E Citygate


6,624

$
0.03


Jan 1 - Dec 31, 11


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Table of Contents

In
July 2009, we entered into a series of transactions whereby we reduced the ceiling on existing natural gas contracts covering 16,900 MMBtu per day from an average ceiling of $11.02 to
$9.00 for the period from January 2010 through December 2010, sold natural gas calls covering 10,000 MMBtu per day at $9.00 for the period from January 2010 through December 2010, and utilized the
proceeds from these transactions to partially fund the purchase of natural gas puts covering 7,800 MMBtu per day at $6.00 and collars covering 15,500 MMBtu per day with limits of $6.00 and $9.10 for
the period from January 2012 through December 2012.

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

Natural Gas

Type of Contract

Counterparty

Basis

Quantity
(MMBtu/d)

Strike Price
($/MMBtu)

TermCall 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, 10Collar

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


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

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

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Table of Contents

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 June 30, 2009, the fair
value of our commodity derivatives was a net asset of $49.1 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 August 5, 2009, there was approximately $544.9 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 will effectively bear interest at a fixed rate of
approximately 8.0% until September 2011. Accordingly, we expect to be subject to interest rate risk until that time only with respect to amounts borrowed in excess of $500.0 million. As of
August 5, 2009, there was approximately $44.9 million borrowed in excess of the aforementioned $500.0 million. A 1.0% increase in interest rates on unhedged variable rate
borrowings of $44.9 million at June 30, 2009, would result in additional annualized interest expense of $0.4 million. As of June 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 June 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 June 30, 2009. Based on the evaluation, those officers believe that:



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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
June 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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

The 2009 annual meeting of our stockholders was held on May 20, 2009 in Denver, Colorado. The following table summarizes the
proposals submitted to a vote of the stockholders and the results of the voting:

For

Against

Abstain or Withhold

Not
VotedElection of directorsDonna L. Lucas


49,995,742





26,980


Dr. M.W. Scoggins


49,993,897





28,825


Richard S. Walker


48,684,971





1,337,751


Approval of the Venoco, Inc. 2008 Employee Stock Purchase Plan


47,179,596


75,786


33,614


2,733,726Ratification of the appointment of Ernst & Young LLP as Venoco, Inc.'s independent registered public accounting
firm


49,992,208


16,459


14,055


Approval of an amendment to the Venoco, Inc. Amended and Restated 2005 Stock Incentive Plan


40,143,661


7,130,652


14,683


2,733,726


Of
the 52,402,703 shares of common stock issued and outstanding as of the record date for the meeting, 50,022,722 shares were present by proxy at the meeting.

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Table of Contents

Item 5.    OTHER INFORMATION

Not Applicable

Item 6.    EXHIBITS

Exhibit
Number

Exhibit10.1

Amendment No. 3 to the Venoco, Inc. Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Appendix B to the Venoco, Inc. Proxy Statement on Schedule 14A filed on April 8,
2009).31.1

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

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

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


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SIGNATURES

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

August 5,
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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