Venoco (VQ) 10-Q 2012 Q3 Quarterly report

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TABLE OF CONTENTS

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2012
Or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 333-123711

Venoco, Inc.

Delaware (State or other jurisdiction of incorporation or organization)	77-0323555 (I.R.S. Employer Identification Number)
370 17th Street, Suite 3900 Denver, Colorado (Address of principal executive offices)	80202-1370 (Zip Code)

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

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

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

        Indicate by check mark whether the registrant 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 ý    NO o

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

Large accelerated filer o Accelerated filer ý Non-accelerated filer o
(Do not check if a
smaller reporting company) Smaller reporting company o

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

        As of September 30, 2012, there were 61,455,060 shares of the issuer's common stock, par value $0.01 per share, issued and outstanding. On October 3, 2012, the issuer completed a go private transaction (see Note 1 to the Financial Statements).

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

        This report on Form 10-Q contains "forward-looking statements" as that term is defined in the Private Securities Litigation Reform Act of 1995. The use of any statements containing the words "anticipate," "intend," "believe," "estimate," "project," "expect," "plan," "should" or similar expressions are intended to identify such statements. Forward-looking statements included in this report relate to, among other things, expected future production, expenses and cash flows, the nature, timing and results of capital expenditure projects, amounts of future capital expenditures, our future debt levels and liquidity, and our future compliance with covenants under our debt agreements. The expectations reflected in such forward-looking statements may prove to be incorrect. Disclosure of important factors that could cause actual results to differ materially from our expectations, or cautionary statements, are included under the heading "Risk Factors" in this report and our Annual Report on Form 10-K for the year ended December 31, 2011. 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, 2011 and such things as:

•

changes in oil and natural gas prices, including reductions in prices that would adversely affect our revenues, income, cash flow from operations, liquidity and reserves;

•

adverse conditions in global credit markets and in economic conditions generally;

•

risks related to our level of indebtedness and a potential inability to effect deleveraging transactions or otherwise reduce those risks;

•

our ability to replace oil and natural gas reserves;

•

risks arising out of our hedging transactions;

•

our inability to access oil and natural gas markets due to operational impediments;

•

uninsured or underinsured losses in, or operational problems affecting, our oil and natural gas operations;

•

inaccuracy in reserve estimates and expected production rates;

•

exploitation, development and exploration results, including in the onshore Monterey shale, where our results will depend on, among other things, our ability to identify productive intervals and drilling and completion techniques necessary to achieve commercial production from those intervals;

•

the consequences of changes we have made, or may make from time to time in the future, to our capital expenditure budget, including the impact of those changes on our production levels, reserves, results of operations and liquidity;

•

our ability to manage expenses, including expenses associated with asset retirement obligations;

•

a lack of available capital and financing, including as a result of a reduction in the borrowing base under our revolving credit facility;

•

the potential unavailability of drilling rigs and other field equipment and services;

•

the existence of unanticipated liabilities or problems relating to acquired businesses or properties;

•

difficulties involved in the integration of operations we have acquired or may acquire in the future;

•

the effect of any business combination, joint venture or other significant transaction we may pursue, or the costs of litigation related thereto;

•

factors affecting the nature and timing of our capital expenditures;

•

the impact and costs related to compliance with or changes in laws or regulations governing or affecting our operations, including changes resulting from the Deepwater Horizon well blowout in the Gulf of Mexico, from the Dodd-Frank Wall Street Reform and Consumer Protection Act or its implementing regulations and from regulations relating to greenhouse gas emissions;

•

delays, denials or other problems relating to our receipt of operational consents and approvals from governmental entities and other parties;

•

environmental liabilities;

•

loss of senior management or technical personnel;

•

natural disasters, including severe weather;

•

acquisitions and other business opportunities (or the lack thereof) that may be presented to and pursued by us;

•

risk factors discussed in this report; and

•

other factors, many of which are beyond our control.

VENOCO, INC.

Form 10-Q for the Quarterly Period Ended September 30, 2012

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION	2
Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets at December 31, 2011 and September 30, 2012	2
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2011 and the Three and Nine Months Ended September 30, 2012	3
	Condensed Consolidated Statements of Changes in Stockholders' Equity for the Nine Months Ended September 30, 2012	4
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and the Nine Months Ended September 30, 2012	5
	Notes to Condensed Consolidated Financial Statements	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	46
Item 4.	Controls and Procedures	50
PART II.	OTHER INFORMATION	51
Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	51
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51
Item 3.	Defaults upon Senior Securities	51
Item 4.	Mine Safety Disclosures	51
Item 5.	Other Information	51
Item 6.	Exhibits	51
Signatures		52

1

PART I—FINANCIAL INFORMATION

VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(In thousands, except shares and per share amounts)

	December 31, 2011			September 30, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	8,165		$	18,208
Accounts receivable		30,017			34,194
Inventories		7,411			5,973
Other current assets		4,296			5,179
Commodity derivatives		47,768			526
Total current assets		97,657			64,080
PROPERTY, PLANT AND EQUIPMENT, AT COST:
Oil and gas properties, full cost method of accounting
Proved		1,971,499			2,118,573
Unproved		52,021			58,734
Accumulated depletion		(1,229,264	)		(1,291,751	)
Net oil and gas properties		794,256			885,556
Other property and equipment, net of accumulated depreciation and amortization of $16,176 and $18,160 at December 31, 2011 and September 30, 2012, respectively		16,209			15,531
Net property, plant and equipment		810,465			901,087
OTHER ASSETS:
Commodity derivatives		3,242			17
Deferred loan costs		15,320			14,039
Other		3,060			5,676
Total other assets		21,622			19,732
TOTAL ASSETS	$	929,744		$	984,899
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	53,098		$	66,591
Interest payable		21,854			14,849
Commodity derivatives		2,490			26,952
Total current liabilities		77,442			108,392
LONG-TERM DEBT		686,958			719,524
COMMODITY DERIVATIVES		308			27,608
ASSET RETIREMENT OBLIGATIONS		92,008			93,143
Total liabilities		856,716			948,667
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Common stock, $.01 par value (200,000,000 shares authorized; 61,596,405 and 61,455,060 shares issued and outstanding at December 31, 2011 and September 30, 2012, respectively)		616			615
Additional paid-in capital		443,470			450,124
Retained earnings (accumulated deficit)		(371,058	)		(414,507	)
Total stockholders' equity		73,028			36,232
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	929,744		$	984,899

See notes to condensed consolidated financial statements.

2

VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(In thousands, except per share amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2012			2011			2012
REVENUES:
Oil and natural gas sales	$	77,296		$	95,377		$	241,533		$	259,701
Other		1,635			1,321			3,877			4,859
Total revenues		78,931			96,698			245,410			264,560
EXPENSES:
Lease operating expense		28,684			22,899			71,360			67,442
Property and production taxes		1,796			1,671			4,783			8,588
Transportation expense		2,367			482			7,023			5,151
Depletion, depreciation and amortization		20,406			22,240			63,810			65,707
Accretion of asset retirement obligations		1,623			1,457			4,821			4,298
General and administrative, net of amounts capitalized		9,236			11,822			27,889			34,052
Total expenses		64,112			60,571			179,686			185,238
Income (loss) from operations		14,819			36,127			65,724			79,322
FINANCING COSTS AND OTHER:
Interest expense, net		16,005			16,498			44,678			48,089
Amortization of deferred loan costs		592			597			1,715			1,751
Interest rate derivative losses (gains), net		—			—			1,083			—
Loss on extinguishment of debt		—			—			1,357			—
Commodity derivative losses (gains), net		(38,572	)		49,089			(15,001	)		72,931
Total financing costs and other		(21,975	)		66,184			33,832			122,771
Income (loss) before income taxes		36,794			(30,057	)		31,892			(43,449	)
Income tax provision (benefit)		—			—			—			—
Net income (loss)	$	36,794		$	(30,057	)	$	31,892		$	(43,449	)
Earnings per common share:
Basic	$	0.60		$	(0.51	)	$	0.53		$	(0.74	)
Diluted	$	0.60		$	(0.51	)	$	0.52		$	(0.74	)
Weighted average common shares outstanding:
Basic		58,738			59,119			57,881			59,045
Diluted		58,830			59,119			58,038			59,045

See notes to condensed consolidated financial statements.

3

VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

(UNAUDITED)

(In thousands)

	Common Stock								Retained Earnings (Accumulated Deficit)
							Additional Paid-in Capital
	Shares			Amount								Total
BALANCE AT DECEMBER 31, 2011		61,596		$	616		$	443,470	$	(371,058	)	$	73,028
Issuance of restricted shares, net of cancellations		(155	)		(1	)		1		—			—
Share-based compensation		—			—			6,520		—			6,520
Issuance of common stock pursuant to Employee Stock Purchase Plan		14			—			133		—			133
Net income (loss)		—			—			—		(43,449	)		(43,449	)
BALANCE AT SEPTEMBER 30, 2012		61,455		$	615		$	450,124	$	(414,507	)	$	36,232

See notes to condensed consolidated financial statements.

4

VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In thousands)

	Nine Months Ended September 30,
	2011			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	31,892		$	(43,449	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization		63,810			65,707
Accretion of asset retirement obligations		4,821			4,298
Share-based compensation		4,966			4,245
Amortization of deferred loan costs		1,715			1,751
Amortization of bond discounts and other non-cash interest		500			566
Loss on extinguishment of debt		1,357			—
Unrealized interest rate swap derivative losses (gains)		(40,064	)		—
Unrealized commodity derivative losses (gains) and amortization of premiums		(3,455	)		113,216
Changes in operating assets and liabilities:
Accounts receivable		(2,113	)		(3,800	)
Inventories		(265	)		1,438
Other current assets		(589	)		(909	)
Income taxes receivable		931			—
Other assets		204			(2,616	)
Accounts payable and accrued liabilities		10,059			4,860
Net premiums paid on derivative contracts		(7,201	)		(10,987	)
Net cash provided by operating activities		66,568			134,320
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties		(189,467	)		(176,734	)
Acquisitions of oil and natural gas properties		(213	)		(175	)
Expenditures for other property and equipment		(1,088	)		(2,399	)
Proceeds from sale of oil and natural gas properties		—			23,342
Net cash (used in) provided by investing activities		(190,768	)		(155,966	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		563,000			200,000
Principal payments on long-term debt		(515,311	)		(168,000	)
Payments for deferred loan costs		(12,548	)		(444	)
Proceeds from issuance of common stock		82,800			—
Stock issuance costs		(629	)		—
Proceeds from stock incentive plans and other		1,873			133
Net cash (used in) provided by financing activities		119,185			31,689
Net increase (decrease) in cash and cash equivalents		(5,015	)		10,043
Cash and cash equivalents, beginning of period		5,024			8,165
Cash and cash equivalents, end of period	$	9		$	18,208
Supplemental Disclosure of Cash Flow Information—
Cash paid for interest	$	43,641		$	54,529
Cash paid (refunded) for income taxes	$	(931	)	$	—
Supplemental Disclosure of Noncash Activities—
Accrued capital expenditures at period end	$	15,017		$	27,077
Increase (decrease) in accrued capital expenditures	$	(5,355	)	$	865

See notes to condensed consolidated financial statements.

5

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.

        Recent Events    On August 26, 2011, the Company's board of directors received a proposal from its then-chairman and chief executive officer, Timothy Marquez, to acquire all of the outstanding shares of common stock of Venoco of which he was not the beneficial owner for $12.50 per share in cash. At the time of the proposal, Mr. Marquez was the beneficial owner of approximately 50.3% of Venoco's common stock. The Company's board of directors formed a special committee comprised of all independent directors to evaluate and consider this proposal as well as third party alternatives. On January 16, 2012, the Company announced that it had entered into a definitive merger agreement with Mr. Marquez and certain of his affiliates pursuant to which he would acquire all shares of which he was not the beneficial owner for $12.50 per share in cash. On June 5, 2012, the shareholders (including a majority of the unaffiliated shareholders) approved the merger and on October 3, 2012 the transaction contemplated by the merger agreement closed. As a result, Venoco's common stock is no longer publicly traded and the Company is wholly owned by Denver Parent Corporation, an entity owned and controlled by Mr. Marquez and his affiliates.

        In connection with the closing of the transaction, Venoco entered into a fifth amended and restated credit agreement related to its revolving credit facility and entered into a $315 million second lien term loan. Details regarding each of the agreements are provided in the long-term debt footnote.

        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. All such adjustments are considered to be of a normal recurring nature. The Company has evaluated subsequent events and transactions for matters that may require recognition or disclosure in these financial statements. Venoco's Annual Report on Form 10-K for the year ended December 31, 2011 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 derivative instruments; (8) accrued liabilities; (9) valuation of share-based

6

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

payments and (10) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates.

        Income Taxes    The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to its year-to-date income or loss, except for discrete items. Income taxes for discrete items are computed and recorded in the period in which the specific transaction occurs.

        The Company has net operating loss carryovers as of December 31, 2011 of $295.7 million for federal income tax purposes as a result of losses incurred before income taxes in 2008 and 2009 as well as taxable losses in each of the tax years from 2007 through 2011. These losses and expected future taxable losses were key considerations that led the Company to provide a valuation allowance against its net deferred tax assets at December 31, 2011 and September 30, 2012, since it cannot conclude that it is more likely than not that its net deferred tax assets will be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings; consistent and sustained pre-tax earnings; sustained or continued improvements in oil and natural gas commodity prices; meaningful incremental oil production and proved reserves from the Company's development efforts at its Southern California legacy properties; consistent, meaningful production and proved reserves from the Company's onshore Monterey shale project; meaningful production and proved reserves from the CO₂ project at the Hastings Complex; and taxable events resulting from one or more deleveraging transactions. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods.

        As long as the Company concludes that it will continue to have a need for a full valuation allowance against its net deferred tax assets, the Company likely will not have any income tax expense or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims or for state income taxes.

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

        Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The Company's unvested restricted stock awards contain nonforfeitable dividend rights and participate equally with common stock with respect to dividends

7

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

issued or declared. However, the Company's unvested restricted stock does not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Consequently, in periods of net loss, the two class method will not have an effect on the Company's basic earnings per share.

        The following table details the weighted average dilutive and anti-dilutive securities, which consist of options and unvested restricted stock, for the periods presented (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2012		2011		2012
Dilutive		3,187		—		3,200		—
Anti-dilutive		593		3,177		559		3,277

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2012			2011			2012
Net income (loss)	$	36,794		$	(30,057	)	$	31,892		$	(43,449	)
Allocation of net income to unvested restricted stock		(1,718	)		—			(1,492	)		—
Net income (loss) allocated to common stock	$	35,076		$	(30,057	)	$	30,400		$	(43,449	)
Basic weighted average common shares outstanding		58,738			59,119			57,881			59,045
Add: dilutive effect of stock options		92			—			157			—
Diluted weighted average common shares outstanding		58,830			59,119			58,038			59,045
Basic earnings per common share	$	0.60		$	(0.51	)	$	0.53		$	(0.74	)
Diluted earnings per common share	$	0.60		$	(0.51	)	$	0.52		$	(0.74	)

        As a result of the completion of the merger transaction on October 3, 2012, the Company no longer has any stock outstanding that is publicly traded or any outstanding restricted stock.

        Related Party Transactions    The Company has entered into a non-exclusive aircraft sublease agreement with TimBer, LLC, a company owned by the Company's executive chairman and former chief executive officer, Timothy Marquez, and his wife. For the nine months ended September 30, 2012, the Company incurred approximately $0.6 million of costs related to the agreement. At September 30, 2012, $0.9 million remains in accounts payable and accrued liabilities due to TimBer, including amounts incurred in 2011.

        Mr. Edward O'Donnell was appointed the COO of the Company in January 2012 and CEO in August 2012. Per the employment agreement entered into in connection with Mr. O'Donnell's

8

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

appointment, the Company agreed to purchase his residence in Santa Barbara County, California to facilitate his relocation from California to Denver, Colorado. In February 2012, the Company purchased Mr. O'Donnell's residence for the appraised value of $1.6 million.

        Recently Issued Accounting Standards—In May 2011, the FASB issued Accounting Standards Update No. 2011-04—Fair Value Measurement—Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs, which amends current U.S. GAAP fair value measurement and disclosure guidance, to converge U.S. GAAP and IFRS requirements for measuring amounts at fair value as well as disclosures about these measurements. The authoritative guidance is effective for interim and annual periods beginning after December 15, 2011. The Company adopted the provisions of the ASU, which has not resulted in a significant impact on the Company's financial statements other than additional disclosures.

        In December 2011, the FASB issued Accounting Standards Update No. 2011-11,Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities ("ASU 2011-11"), which requires that an entity disclose both gross and net information about instruments and transactions that are either eligible for offset in the balance sheet or subject to an agreement similar to a master netting agreement, including derivative instruments. ASU 2011-11 was issued to facilitate comparison between U.S. GAAP and IFRS financial statements by requiring enhanced disclosures, but does not change existing U.S. GAAP that permits balance sheet offsetting. This authoritative guidance is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The adoption of this authoritative guidance will not have an impact on the Company's financial position or results of operations, but will require enhanced disclosures regarding its derivative instruments.

2. ACQUISITIONS AND SALES OF PROPERTIES

        In May 2012, the Company sold its interests in the Santa Clara Avenue field in Southern California for $23.4 million (after closing adjustments). The Company applied $20 million of the proceeds to pay down the existing balance on its revolving credit facility. No gain or loss was recognized on the sale as the Company recorded the net proceeds as a reduction to the capitalized costs of its oil and natural gas properties.

9

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

3. LONG-TERM DEBT

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

	December 31, 2011		September 30, 2012
Revolving credit agreement due March 2016	$	43,000	$	75,000
11.50% senior notes due October 2017 (face value $150,000)		143,958		144,524
8.875% senior notes due February 2019 (face value $500,000)		500,000		500,000
Total long-term debt		686,958		719,524
Less: current portion of long-term debt		—		—
Long-term debt, net of current portion	$	686,958	$	719,524

        Revolving Credit Facility.    In October 2012, the Company entered into a fifth amended and restated credit agreement which maintained the size of its revolving credit facility at $500 million and the maturity date of the facility at March 31, 2016. The borrowing base is subject to redetermination twice each year, and may be redetermined at other times at the Company's request or at the request of the lenders (currently $175 million). The availability under the facility is limited to the commitments of the participating lenders, which currently total $156 million. 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 subsidiaries other than Ellwood Pipeline, Inc. The collateral also secures the Company's obligations to hedging counterparties that are also lenders, or affiliates of lenders, under the facility. Loans made under the revolving credit facility are designated, at the Company's option, as either "Base Rate Loans" or "LIBO Rate Loans." Loans designated as Base Rate Loans under the facility bear interest at a floating rate equal to (i) the greater of (x) the administrative agent's announced prime rate, (y) the federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.0%, plus (ii) an applicable margin ranging from 1.25% to 2.00%, based on 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. The applicable margin for both Base Rate Loans and LIBO Rate Loans will be increased by 0.50% in the event that the Company's debt to adjusted EBITDA ratio exceeds 3.75 to 1.00 on the last day of each of the two fiscal quarters most recently ended. A commitment fee of 0.50% per annum is payable with respect to unused borrowing availability under the facility. The agreement governing the facility contains customary representations, warranties, events of default, indemnities and covenants, including operational covenants that restrict the Company's ability to incur indebtedness and financial covenants that require the Company to maintain specified ratios of current assets to current liabilities, debt to EBITDA and interest coverage. The agreement also restricts the amount of exploratory capital expenditures the Company can incur related to the onshore Monterey project when the debt to EBITDA ratio exceeds 3.75 to 1.00.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

3. LONG-TERM DEBT (Continued)

        As of November 6, 2012, the Company had $101.0 million outstanding on the facility and had available borrowing capacity of $51.2 million under the facility, net of the outstanding balance and $3.8 million in outstanding letters of credit.

        Second Lien Term Loan Facility.    In connection with the going private transaction, the Company entered into a $315.0 million senior secured second lien term loan facility in October 2012 (the "second lien term loan facility"), which was issued at 98% of the principal amount of the facility. Loans made under the second lien term loan 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 (x) the administrative agent's announced prime rate, (y) the federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.0%, plus (ii) 6.00%. Loans designated as LIBO Rate Loans bear interest at LIBOR plus 7.00%. Per the second lien term loan agreement, LIBOR shall not be less than 1.50%.

        The agreement governing the second lien term loan facility contains customary representations, warranties, events of default and indemnities. The agreement also contains certain customary covenants, including covenants that restrict the Company's ability to incur additional indebtedness and financial covenants that require the Company to maintain specified ratios of debt to adjusted EBITDA, interest coverage and collateral coverage. Additionally, the agreement restricts the amount of exploratory capital expenditures the Company can incur related to its onshore Monterey project when the debt to EBITDA ratio exceeds 5.0 to 1.0. 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. The maturity date of the principal on the second lien term loan facility is June 30, 2017.

        The Company may from time to time make optional prepayments of amounts borrowed under the second lien term loan facility, if no amounts are outstanding under the revolving credit facility, at a 3.0% premium if paid prior to October 3, 2013 with the premium declining 1% each year through October 3, 2015 and then at par thereafter. Amounts prepaid under the second lien term loan facility may not be reborrowed.

        8.875% Senior Notes.    In February 2011, the Company issued $500 million in 8.875% senior notes due in February 2019 at par. Concurrently with the sale of the 8.875% senior notes, the Company repaid in full the outstanding principal balance of $455.3 million on its then outstanding second lien term loan. The 8.875% senior notes pay interest semi-annually in arrears on February 15 and August 15 of each year. The Company may redeem the notes prior to February 15, 2015 at a "make whole premium" defined in the indenture. Beginning February 15, 2015, the Company may redeem the notes at a redemption price of 104.438% of the principal amount and declining to 100% by February 15, 2017. The 8.875% senior notes are senior unsecured obligations and contain operational covenants that, among other things, limit the Company's ability to make investments, incur additional indebtedness, issue preferred stock, pay dividends, repurchase its stock, create liens or sell assets.

        11.50% Senior Notes.    In October 2009, the Company issued $150.0 million of 11.50% senior notes due October 2017 at a price of 95.03% of par. The senior notes pay interest semi-annually in arrears on April 1 and October 1 of each year. The Company may redeem the senior notes prior to October 1,

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(UNAUDITED)

3. LONG-TERM DEBT (Continued)

2013 at a "make-whole price" defined in the indenture. Beginning October 1, 2013, the Company may redeem the notes at a redemption price equal to 105.75% of the principal amount and declining to 100% by October 1, 2016. The 11.50% notes are senior unsecured obligations and contain covenants that, among other things, limit the Company's ability to make investments, incur additional debt, issue preferred stock, pay dividends, repurchase its stock, create liens or sell assets.

        The Company was in compliance with all debt covenants at September 30, 2012.

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS

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

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

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

        The Company has paid premiums related to certain of its outstanding derivative contracts. These premiums are amortized into commodity derivative (gains) losses over the period for which the contracts are effective. At September 30, 2012, the balance of unamortized net derivative premiums paid was $12.2 million, of which $1.1 million will be amortized in the remainder of 2012 and $3.7 million will be amortized in each of the years from 2013 through 2015.

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(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011			2012		2011			2012
Realized commodity derivative (gains) losses	$	(2,571	)	$	7,597	$	(11,546	)	$	(40,285	)
Amortization of commodity derivative premiums		1,990			1,203		5,970			11,222
Unrealized commodity derivative (gains) losses for changes in fair value:		(37,991	)		40,289		(9,425	)		101,994
Commodity derivative (gains) losses	$	(38,572	)	$	49,089	$	(15,001	)	$	72,931

        During the first nine months of 2012, the Company unwound certain of its then existing oil and natural gas derivative contracts and received $52.2 million. The Company also unwound certain oil contracts in the second quarter of 2011 for which it received $2.0 million. The gains recognized are included in realized commodity derivative losses (gains).

        As of September 30, 2012, the Company had entered into swap, collar and option agreements related to its oil and natural gas production. The aggregate economic effects of those agreements are summarized below. Location and quality differentials attributable to the Company's properties are not included in the following prices. The agreements provide for monthly settlement based on the

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

differential between the agreement price and the price per the applicable index (NYMEX WTI ("WTI") (oil), Inter-Continental Exchange Brent ("Brent") (oil) or NYMEX Henry Hub (natural gas)).

	Oil (NYMEX WTI)				Oil (Brent)				Natural Gas (NYMEX Henry Hub)
	Barrels/day		Weighted Avg. Prices per Bbl		Barrels/day		Weighted Avg. Prices per Bbl		MMBtu/day		Weighted Avg. Prices per MMBtu
October 1 - December 31, 2012:
Swaps		—	$	—		—	$	—		29,500	$	3.00
Collars(1)		6,500	$	80.00/$118.15		—	$	—		—	$	—
Puts(1)		2,000	$	60.00		—	$	—		—	$	—
January 1 - December 31, 2013:
Swaps		—	$	—		—	$	—		24,000	$	3.47
Collars		—	$	—		4,600	$	90.00/$102.47		—	$	—
January 1 - December 31, 2014:
Swaps		—	$	—		—	$	—		18,600	$	3.82
Collars		—	$	—		4,100	$	90.00/$98.59		—	$	—
January 1 - December 31, 2015:
Collars		—	$	—		3,675	$	90.00/$98.95		15,000	$	3.50/$4.66

(1)

Reflects the impact of call spreads and purchased calls, which are transactions we entered into for the purpose of modifying or eliminating the ceiling (or call) portion of certain collar arrangements.

        In October 2012, the Company entered into oil swaps for 1,350 barrels per day at an average price of $106.52 per barrel for the period from January 1, 2013 to December 31, 2013.

        The Company has also entered into certain oil and natural gas basis swaps. The oil basis swaps fix the differential between the WTI crude price index and Brent. Historically the two price indexes have demonstrated a close correlation with each other and with the Southern California indexes on which the Company sells a significant percentage of its oil. However, the relationship between WTI and Brent has diverged, favoring Brent crude. The Southern California indexes most relevant to the Company have tracked more closely with Brent prices than to WTI. The natural gas basis swaps fix the differential between the Henry Hub price and the PG&E Citygate price, the index on which the

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

majority of the Company's natural gas is sold. The Company's oil and natural gas basis swaps as of September 30, 2012 are presented below:

	Oil Basis Swaps (NYMEX WTI)						Natural Gas Basis Swaps (NYMEX Henry Hub)
	Floating Index		Weighted Avg. Bbls/Day		Weighted Avg. Basis Differential to NYMEX WTI (per Bbl)		Floating Index	Weighted Avg. MMBtu/Day		Weighted Avg. Basis Differential to NYMEX HH (per MMBtu)
Basis Swaps:
October 1 - December 31, 2012		Brent Crude		8,500	$	6.82	—		—	$	—
January 1 - December 31, 2013		Brent Crude		3,900	$	5.88	PG&E Citygate		24,000	$	0.24
January 1 - December 31, 2014		—		—	$	—	PG&E Citygate		18,600	$	0.24
January 1 - December 31, 2015		—		—	$	—	PG&E Citygate		15,000	$	0.24

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

        In February 2011, the Company repaid the principal balance outstanding on the second lien term loan from proceeds received from the issuance of the 8.875% senior notes, which reduced the Company's debt subject to variable rate interest to any amounts which may be outstanding under the Company's revolving credit facility. As a result, the Company settled the interest rate swaps for $38.1 million in February 2011. The Company incurred a realized loss of $41.1 million and an unrealized gain of $40.0 million in the nine months ended September 30, 2011, under its interest rate derivative contracts. These amounts are reported in interest rate derivative (gains) losses on the consolidated statements of operations.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)

        Fair Value of Derivative Instruments.    The estimated fair values of derivatives included in the consolidated balance sheets at December 31, 2011 and September 30, 2012 are summarized below. The net fair value of the Company's derivatives changed by $102.2 million from a net asset of $48.2 million at December 31, 2011 to a net liability of $54.0 million at September 30, 2012, primarily due to (i) changes in the futures prices for oil and natural gas, which are used in the calculation of the fair value of commodity derivatives, (ii) settlement of commodity derivative positions during the current period and (iii) changes to the Company's commodity derivative portfolio in 2012. 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 its derivative contracts as hedging instruments. The main headings represent the balance sheet captions for the contracts presented.

	December 31, 2011			September 30, 2012
Current Assets—Commodity derivatives:
Oil derivative contracts	$	6,190		$	526
Gas derivative contracts		41,578			—
		47,768			526
Other Assets—Commodity derivatives:
Oil derivative contracts		3,230			17
Gas derivative contracts		12			—
		3,242			17
Current Liabilities—Commodity derivatives:
Oil derivative contracts		(2,490	)		(23,569	)
Gas derivative contracts		—			(3,383	)
		(2,490	)		(26,952	)
Commodity derivatives:
Oil derivative contracts		(308	)		(22,731	)
Gas derivative contracts		—			(4,877	)
		(308	)		(27,608	)
Net derivative asset (liability)	$	48,212		$	(54,017	)

5. FAIR VALUE MEASUREMENTS

        Fair value is defined as the price that would be received in the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

5. FAIR VALUE MEASUREMENTS (Continued)

Company classifies fair value balances based on the observability of those inputs. The FASB has established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).

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

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

        Level 2—Pricing inputs are other than quoted prices in active markets included in level 1, but are either directly or indirectly observable as of the reported date and for substantially the full term of the instrument. Inputs may include quoted prices for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies.

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

        Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of September 30, 2012 (in thousands).

	Level 1		Level 2			Level 3		Fair Value as of September 30, 2012
Assets (Liabilities):
Commodity derivative contracts	$	—	$	543		$	—	$	543
Commodity derivative contracts		—		(54,560	)		—		(54,560	)

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

        Fair Value of Financial Instruments.    The Company's financial instruments consist primarily of cash and cash equivalents, accounts receivable and payable, derivatives (discussed above) and long-term

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

5. FAIR VALUE MEASUREMENTS (Continued)

debt. All of the Company's financial instruments, except derivatives, are presented on the balance sheet at carrying value. 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 (level 2 measurement). The fair value of the second lien term loan facility and the senior notes listed in the tables below were based on quoted market prices (level 1 inputs). The values in the table below are presented in thousands.

	December 31, 2011						September 30, 2012
	Carrying Amount			Estimated Fair Value			Carrying Amount			Estimated Fair Value
Commodity derivatives—Assets	$	51,010		$	51,010		$	543		$	543
Commodity derivatives—Liabilities		(2,798	)		(2,798	)		(54,560	)		(54,560	)
Revolving credit agreement		(43,000	)		(43,000	)		(75,000	)		(75,000	)
11.50% senior notes		(143,958	)		(154,500	)		(144,524	)		(156,750	)
8.875% senior notes		(500,000	)		(455,000	)		(500,000	)		(428,750	)

6. ASSET RETIREMENT OBLIGATIONS

        The Company's asset retirement obligations 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 at inception (non-recurring fair value measurement) by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred (level 3 input), the Company's credit adjusted discount rates (level 2 input), inflation rates (level 2 input) and estimated dates of abandonment (level 3 inputs). The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

6. ASSET RETIREMENT OBLIGATIONS (Continued)

        The following table summarizes the activities for the Company's asset retirement obligations for the nine months ended September 30, 2011 and 2012 (in thousands):

	Nine Months Ended September 30, 2011			Nine Months Ended September 30, 2012
Asset retirement obligations at beginning of period	$	94,221		$	92,508
Revisions of estimated liabilities		(15,095	)		(59	)
Liabilities incurred/acquired		3,365			1,060
Liabilities settled		(251	)		(504	)
Disposition of properties		—			(3,160	)
Accretion expense		4,821			4,298
Asset retirement obligations at end of period		87,061			94,143
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)		(500	)		(1,000	)
Long-term asset retirement obligations	$	86,561		$	93,143

        Discount rates used to calculate the present value vary depending on the estimated timing of the obligation, but typically range between 4% and 9%.

7. CAPITAL STOCK

        The Company had 65.6 million shares of common stock issued or reserved for issuance at September 30, 2012. At September 30, 2012, the Company had 61.5 million shares of common stock issued and outstanding, of which 2.3 million shares were restricted stock granted under the Company's 2005 stock incentive plan. At September 30, 2012, the Company had approximately 0.8 million options outstanding and 3.0 million shares available to be issued pursuant to awards under its stock incentive plans, including the 2008 Employee Stock Purchase Plan.

        On October 3, 2012, Venoco's former CEO and executive chairman completed a transaction whereby he purchased all of the outstanding stock of the Company for $12.50 per share. As a result, Venoco's common stock is no longer publicly traded and the Company is wholly owned by Denver Parent Corporation, an entity owned and controlled by Mr. Marquez and his affiliates. In connection with the going private transaction, all of the 29,936,378 shares of Venoco stock outstanding following the merger is pledged as security for debt of Denver Parent Corporation, which was incurred in connection with the going private transaction. At closing, all then-outstanding shares of common stock, other than shares owned and controlled by Mr. Marquez and his affiliates, were converted into the right to receive cash of $12.50 per share pursuant to the terms of the merger agreement.

8. SHARE-BASED PAYMENTS

        The Company has granted options to directors and certain employees and officers of the Company other than its former CEO, under its 2000 and 2005 Stock Plans (the "Stock Plans"). As of September 30, 2012, there were a total of 830,055 options outstanding with a weighted average exercise

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

8. SHARE-BASED PAYMENTS (Continued)

price of $13.45 ($6.00 to $20.00), all of which have vested. The options typically have a maximum life of 10 years.

        As of September 30, 2012, there were a total of 2,331,726 shares of restricted stock outstanding under the Company's 2005 stock incentive plan, including 990,550 shares granted to Mr. Marquez. Restricted shares subject to service conditions only generally vest over a four year period, with 25% vesting on each subsequent anniversary of the grant date. The grant date fair value of restricted stock subject to service conditions only is determined by the Company's closing stock price on the day prior to the date of grant. The vesting of 1,726,829 shares was also subject to market conditions based on the Company's total shareholder return in comparison to peer group companies and/or an industry index for each calendar year. Shares of restricted stock subject to market conditions granted prior to 2011 have a four year period over which vesting may occur. For grants issued in 2011, this period was expanded by three years in which a portion of the available shares could vest. The weighted-average fair value of the restricted shares subject to market conditions was derived using a Monte Carlo technique. The estimated grant date fair values of restricted share awards are recognized as expense over the requisite service periods.

        As of September 30, 2012, there was $10.4 million of total unrecognized compensation cost related to restricted stock, which was expected to be amortized over a weighted average period of 1.9 years. All compensation cost related to stock options has been recognized.

        As discussed above, the going private transaction closed on October 3, 2012 and the Company no longer has publicly traded stock. As a result of the transaction, each share of unvested restricted stock held by employees outstanding on October 3, 2012 was converted to a right to receive $12.50 on a vesting schedule consistent with the original terms of the grant. The market conditions to which certain restricted shares were subject will be deemed to have been met at the target level. All unvested restricted stock held by members of the board of directors, other than Tim Marquez, were cancelled. Additionally, each outstanding option was converted into a right to receive a cash payment equal to the number of options multiplied by the amount (if any) by which $12.50 exceeds the option's exercise price. The Company is currently finalizing plans for a new long-term incentive equity-based award plan under a private company scenario to replace the existing Stock Plans. Once the new long-term incentive equity-based award plans are finalized, the Company intends to issue annual grants of equity or equity-related compensation in 2012.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2012			2011			2012
General and administrative expense	$	2,430		$	1,790		$	7,140		$	5,850
Oil and natural gas production expense		260			160			890			670
Total share-based compensation costs		2,690			1,950			8,030			6,520
Less: share-based compensation costs capitalized		(1,127	)		(453	)		(3,064	)		(2,275	)
Share-based compensation expensed	$	1,563		$	1,497		$	4,966		$	4,245

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

8. SHARE-BASED PAYMENTS (Continued)

        The following summarizes the Company's stock option activity for the nine months ended September 30, 2012:

	Options			Weighted Average Exercise Price
Outstanding, start of period		846,055		$	13.53
Granted		—		$	—
Exercised		—		$	—
Cancelled		(16,000	)	$	17.73
Outstanding, end of period		830,055		$	13.45
Exercisable, end of period		830,055		$	13.45

        The following summarizes the Company's unvested restricted stock award activity for the nine months ended September 30, 2012:

	Shares			Weighted Average Grant Date Fair Value
Non-vested, start of period		2,815,244		$	11.35
Granted		1,500		$	8.22
Vested		(328,749	)	$	11.63
Forfeited		(156,269	)	$	11.02
Non-vested, end of period		2,331,726		$	11.33

        The Company also provided a non-compensatory Employee Stock Purchase Plan (the "ESPP"). Participation in the ESPP was open to all employees, other than executive officers, who met limited qualifications. Under the terms of the ESPP, employees were 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 were limited to $25,000 of common stock purchased in any calendar year. In connection with the closing of the going private transaction, the ESPP was terminated.

9. CONTINGENCIES

        Beverly Hills Litigation—Between June 2003 and April 2005, six lawsuits were filed against the Company, certain other energy companies, the City of Beverly Hills and the Beverly Hills Unified School District 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 (the "Beverly Hills Lawsuits"). 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. All cases were consolidated before one judge. Twelve "representative" plaintiffs were selected to have their cases tried first, while all of the other plaintiffs'

21

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

9. CONTINGENCIES (Continued)

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. In July 2012 the Company entered into a settlement agreement, for an immaterial amount, pursuant to which all pending cases against the defendants will be dismissed with prejudice.

        Certain defendants and related parties have made claims for indemnity against the Company which the Company is disputing. An insurer for the City of Beverly Hills has filed suit against the Company and the Company's predecessors in interest seeking recovery of approximately $1.2 million spent by the insurer in defending the city in the Beverly Hills Lawsuits. The Company believes that this suit and other potential claims for indemnity are without merit. Based on information known to the Company, the Company does not believe that it is probable that the pending and potential indemnity claims will result in a material judgment against the Company. Therefore, no liability has been accrued.

        State Lands Commission Royalty Litigation—In November 2011, the California State Lands Commission (SLC) filed suit against the Company in Santa Barbara County alleging that the Company underpaid royalties on oil and gas produced from the South Ellwood field in California for the period from August 1, 1997 through May 2011 by approximately $9.5 million. The case has since been removed to Los Angeles County, California. The principal issues in dispute are (i) the oil price on which royalties should be calculated and (ii) whether the Company is entitled to deduct the cost of transporting oil from the South Ellwood Field to the point of sale in calculating the royalty. With respect to the oil price, the Company has paid royalties based on the price the Company actually received in arms-length transactions. The SLC contends that the Company should be paying royalties based on the higher of the price actually received and the highest "posted price" for oil sold in the Midway Sunset field, near Bakersfield, California. With respect to the deduction of transportation costs, the Company believes that state law allows the Company to adjust the sale price to reflect the cost of delivering the oil from the field to the point of sale. In February 2012 the Company filed a cross-complaint against the SLC alleging that the Company had overpaid royalties on oil and gas produced from the South Ellwood field by approximately $4.3 million. Most of the overpayment is attributable to the failure by the Company to deduct all transportation costs associated with marketing crude oil.

        The Company believes the position of the SLC is without merit and the Company intends to vigorously contest the suit and to enforce its right to receive a refund of royalties it may have overpaid. The Company does not believe that it is probable that a material judgment against the Company will result. Therefore, no liability has been accrued.

        Delaware Litigation—In August 2011 Timothy Marquez, the then-chairman and chief executive officer of the Company, submitted a nonbinding proposal to the board of directors of the Company to acquire all of the shares of the Company he does not beneficially own for $12.50 per share in cash (the "Marquez Proposal"). As a result of that proposal, four lawsuits were filed in the Delaware Court of Chancery in 2011 against the Company and each of its directors by shareholders alleging that the Company and its directors had breached their fiduciary duties to the shareholders in connection with the Marquez Proposal. A fifth lawsuit filed in 2011, also in the Delaware Court of Chancery, named only Mr. Marquez as a defendant. On January 16, 2012, the Company announced it had entered into a

22

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

9. CONTINGENCIES (Continued)

merger agreement with Mr. Marquez and certain of his affiliates pursuant to which, at closing, each of the shareholders other than Mr. Marquez and his affiliates would receive $12.50 for each share of Company stock (the "Merger"). Following announcement of the merger agreement, four additional suits were filed in Delaware and three suits were filed in federal court in Colorado naming as defendants the Company and each of its directors. Each action seeks certification as a class action. Plaintiffs in both the Delaware and Colorado actions challenge the Merger and allege, among other things, that the consideration paid was inadequate. The complaints filed in Delaware were consolidated. The Colorado actions have been administratively closed pending resolution of the Delaware case. The Company has reviewed the allegations contained in the complaints and believes they are without merit.

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

10. GUARANTOR FINANCIAL INFORMATION

        All subsidiaries of the Company other than Ellwood Pipeline Inc. ("Guarantors") have fully and unconditionally guaranteed, on a joint and several basis, the Company's obligations under its 11.50% and 8.875% senior notes. Ellwood Pipeline, Inc. is not a Guarantor (the "Non-Guarantor Subsidiary"). The condensed consolidating financial information for prior periods has been revised to reflect the guarantor and non-guarantor status of the Company's subsidiaries as of September 30, 2012. 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.

23

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

	Venoco, Inc.		Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	8,165	$	—		$	—		$	—		$	8,165
Accounts receivable		29,492		137			388			—			30,017
Inventories		7,411		—			—			—			7,411
Other current assets		4,296		—			—			—			4,296
Commodity derivatives		47,768		—			—			—			47,768
TOTAL CURRENT ASSETS		97,132		137			388			—			97,657
PROPERTY, PLANT & EQUIPMENT, NET		980,041		(184,110	)		14,534			—			810,465
COMMODITY DERIVATIVES		3,242		—			—			—			3,242
INVESTMENTS IN AFFILIATES		529,494		—			—			(529,494	)		—
OTHER		18,320		60			—			—			18,380
TOTAL ASSETS	$	1,628,229	$	(183,913	)	$	14,922		$	(529,494	)	$	929,744
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	53,098	$	—		$	—		$	—		$	53,098
Interest payable		21,854		—			—			—			21,854
Commodity derivatives		2,490		—			—			—			2,490
TOTAL CURRENT LIABILITIES:		77,442		—			—			—			77,442
LONG-TERM DEBT		686,958		—			—			—			686,958
COMMODITY DERIVATIVES		308		—			—			—			308
ASSET RETIREMENT OBLIGATIONS		89,604		1,733			671			—			92,008
INTERCOMPANY PAYABLES (RECEIVABLES)		700,889		(652,294	)		(48,595	)		—			—
TOTAL LIABILITIES		1,555,201		(650,561	)		(47,924	)		—			856,716
TOTAL STOCKHOLDERS' EQUITY		73,028		466,648			62,846			(529,494	)		73,028
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,628,229	$	(183,913	)	$	14,922		$	(529,494	)	$	929,744

24

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS
AT SEPTEMBER 30, 2012
(in thousands)

	Venoco, Inc.		Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	18,208	$	—		$	—		$	—		$	18,208
Accounts receivable		32,662		118			1,414			—			34,194
Inventories		5,973		—			—			—			5,973
Other current assets		5,179		—			—			—			5,179
Commodity derivatives		526		—			—			—			526
TOTAL CURRENT ASSETS		62,548		118			1,414			—			64,080
PROPERTY, PLANT & EQUIPMENT, NET		1,065,085		(184,138	)		20,140			—			901,087
COMMODITY DERIVATIVES		17		—			—			—			17
INVESTMENTS IN AFFILIATES		539,818		—			—			(539,818	)		—
OTHER		19,655		60			—			—			19,715
TOTAL ASSETS	$	1,687,123	$	(183,960	)	$	21,554		$	(539,818	)	$	984,899
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	66,591	$	—		$	—		$	—		$	66,591
Interest payable		14,849		—			—			—			14,849
Commodity derivatives		26,952		—			—			—			26,952
TOTAL CURRENT LIABILITIES:		108,392		—			—			—			108,392
LONG-TERM DEBT		719,524		—			—			—			719,524
COMMODITY DERIVATIVES		27,608		—			—			—			27,608
ASSET RETIREMENT OBLIGATIONS		91,065		1,379			699			—			93,143
INTERCOMPANY PAYABLES (RECEIVABLES)		704,302		(652,864	)		(51,438	)		—			—
TOTAL LIABILITIES		1,650,891		(651,485	)		(50,739	)		—			948,667
TOTAL STOCKHOLDERS' EQUITY		36,232		467,525			72,293			(539,818	)		36,232
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,687,123	$	(183,960	)	$	21,554		$	(539,818	)	$	984,899

25

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2011 (Unaudited)
(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
REVENUES:
Oil and natural gas sales	$	76,907		$	389		$	—		$	—		$	77,296
Other		1,528			14			1,206			(1,113	)		1,635
Total revenues		78,435			403			1,206			(1,113	)		78,931
EXPENSES:
Lease operating expenses		28,172			12			500			—			28,684
Property and production taxes		1,919			(190	)		67			—			1,796
Transportation expense		3,392			—			—			(1,025	)		2,367
Depletion, depreciation and amortization		20,203			26			177			—			20,406
Accretion of asset retirement obligations		1,572			33			18			—			1,623
General and administrative, net of amounts capitalized		9,206			—			118			(88	)		9,236
Total expenses		64,464			(119	)		880			(1,113	)		64,112
Income (loss) from operations		13,971			522			326			—			14,819
FINANCING COSTS AND OTHER:
Interest expense, net		17,071			—			(1,066	)		—			16,005
Amortization of deferred loan costs		592			—			—			—			592
Commodity derivative losses (gains), net		(38,572	)		—			—			—			(38,572	)
Total financing costs and other		(20,909	)		—			(1,066	)		—			(21,975	)
Equity in subsidiary income		1,187			—			—			(1,187	)		—
Income (loss) before income taxes		36,067			522			1,392			(1,187	)		36,794
Income tax provision (benefit)		(727	)		199			528			—			—
Net income (loss)	$	36,794		$	323		$	864		$	(1,187	)	$	36,794

26

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2012 (Unaudited)
(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries		Non-Guarantor Subsidiary			Eliminations			Consolidated
REVENUES:
Oil and natural gas sales	$	95,032		$	345	$	—		$	—		$	95,377
Other		714			—		4,121			(3,514	)		1,321
Total revenues		95,746			345		4,121			(3,514	)		96,698
EXPENSES:
Lease operating expenses		22,376			8		515			—			22,899
Property and production taxes		1,460			—		211			—			1,671
Transportation expense		3,905			4		—			(3,427	)		482
Depletion, depreciation and amortization		22,005			26		209			—			22,240
Accretion of asset retirement obligations		1,419			28		10			—			1,457
General and administrative, net of amounts capitalized		11,793			—		116			(87	)		11,822
Total expenses		62,958			66		1,061			(3,514	)		60,571
Income (loss) from operations		32,788			279		3,060			—			36,127
FINANCING COSTS AND OTHER:
Interest expense, net		17,488			—		(990	)		—			16,498
Amortization of deferred loan costs		597			—		—			—			597
Commodity derivative losses (gains), net		49,089			—		—			—			49,089
Total financing costs and other		67,174			—		(990	)		—			66,184
Equity in subsidiary income		2,685			—		—			(2,685	)		—
Income (loss) before income taxes		(31,701	)		279		4,050			(2,685	)		(30,057	)
Income tax provision (benefit)		(1,646	)		106		1,540			—			—
Net income (loss)	$	(30,055	)	$	173		2,510		$	(2,685	)	$	(30,057	)

27

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2011 (Unaudited)
(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
REVENUES:
Oil and natural gas sales	$	240,345		$	1,188		$	—		$	—		$	241,533
Other		3,590			42			3,413			(3,168	)		3,877
Total revenues		243,935			1,230			3,413			(3,168	)		245,410
EXPENSES:
Lease operating expense		70,055			46			1,259			—			71,360
Property and production taxes		5,020			(336	)		99			—			4,783
Transportation expense		9,927			—			—			(2,904	)		7,023
Depletion, depreciation and amortization		63,265			78			467			—			63,810
Accretion of asset retirement obligations		4,669			97			55			—			4,821
General and administrative, net of amounts capitalized		27,801			1			351			(264	)		27,889
Total expenses		180,737			(114	)		2,231			(3,168	)		179,686
Income (loss) from operations		63,198			1,344			1,182			—			65,724
FINANCING COSTS AND OTHER:
Interest expense, net		47,826			—			(3,148	)		—			44,678
Amortization of deferred loan costs		1,715			—			—			—			1,715
Interest rate derivative losses (gains), net		1,083			—			—			—			1,083
Loss on extinguishment of debt		1,357			—			—			—			1,357
Commodity derivative losses (gains), net		(15,001	)		—			—			—			(15,001	)
Total financing costs and other		36,980			—			(3,148	)		—			33,832
Equity in subsidiary income		3,518			—			—			(3,518	)		—
Income (loss) before income taxes		29,736			1,344			4,330			(3,518	)		31,892
Income tax provision (benefit)		(2,156	)		511			1,645			—			—
Net income (loss)	$	31,892		$	833		$	2,685		$	(3,518	)	$	31,892

28

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2012 (Unaudited)
(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries		Non-Guarantor Subsidiary			Eliminations			Consolidated
REVENUES:
Oil and natural gas sales	$	258,632		$	1,069	$	—		$	—		$	259,701
Other		3,391			18		9,122			(7,672	)		4,859
Total revenues		262,023			1,087		9,122			(7,672	)		264,560
EXPENSES:
Lease operating expense		66,047			35		1,360			—			67,442
Property and production taxes		8,344			1		243			—			8,588
Transportation expense		12,557			4		—			(7,410	)		5,151
Depletion, depreciation and amortization		65,071			78		558			—			65,707
Accretion of asset retirement obligations		4,177			92		29			—			4,298
General and administrative, net of amounts capitalized		33,951			1		362			(262	)		34,052
Total expenses		190,147			211		2,552			(7,672	)		185,238
Income (loss) from operations		71,876			876		6,570			—			79,322
FINANCING COSTS AND OTHER:
Interest expense, net		50,965			—		(2,876	)		—			48,089
Amortization of deferred loan costs		1,751			—		—			—			1,751
Commodity derivative losses (gains), net		72,931			—		—			—			72,931
Total financing costs and other		125,647			—		(2,876	)		—			122,771
Equity in subsidiary income		6,401			—		—			(6,401	)		—
Income (loss) before income taxes		(47,370	)		876		9,446			(6,401	)		(43,449	)
Income tax provision (benefit)		(3,923	)		333		3,590			—			—
Net income (loss)	$	(43,447	)	$	543	$	5,856		$	(6,401	)	$	(43,449	)

29

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 2011 (Unaudited)
(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations		Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	60,262		$	1,463		$	4,843		$	—	$	66,568
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties		(187,107	)		66			(2,426	)		—		(189,467	)
Acquisitions of oil and natural gas properties		(213	)		—			—			—		(213	)
Expenditures for property and equipment and other		(1,088	)		—			—			—		(1,088	)
Net cash provided by (used in) investing activities		(188,408	)		66			(2,426	)		—		(190,768	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from (repayments of) intercompany borrowings		3,946			(1,529	)		(2,417	)		—		—
Proceeds from long-term debt		563,000			—			—			—		563,000
Principal payments on long-term debt		(515,311	)		—			—			—		(515,311	)
Payments for deferred loan costs		(12,548	)		—			—			—		(12,548	)
Proceeds from issuance of common stock		82,800			—			—			—		82,800
Stock issuance costs		(629	)		—			—			—		(629	)
Proceeds from stock incentive plans and other		1,873			—			—			—		1,873
Net cash provided by (used in) financing activities		123,131			(1,529	)		(2,417	)		—		119,185
Net increase (decrease) in cash and cash equivalents		(5,015	)		—			—			—		(5,015	)
Cash and cash equivalents, beginning of period		5,024			—			—			—		5,024
Cash and cash equivalents, end of period	$	9		$	—		$	—		$	—	$	9

30

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 2012 (Unaudited)
(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations		Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	124,248		$	1,065		$	9,007		$	—	$	134,320
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties		(170,545	)		(50	)		(6,139	)		—		(176,734	)
Acquisitions of oil and natural gas properties		(175	)		—			—			—		(175	)
Expenditures for property and equipment and other		(2,399	)		—			—			—		(2,399	)
Proceeds from sale of oil and natural gas properties		23,342			—			—			—		23,342
Net cash provided by (used in) investing activities		(149,777	)		(50	)		(6,139	)		—		(155,966	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from (repayments of) intercompany borrowings		3,883			(1,015	)		(2,868	)		—		—
Proceeds from long-term debt		200,000			—			—			—		200,000
Principal payments on long-term debt		(168,000	)		—			—			—		(168,000	)
Payments for deferred loan costs		(444	)		—			—			—		(444	)
Proceeds from stock incentive plans and other		133			—			—			—		133
Net cash provided by (used in) financing activities		35,572			(1,015	)		(2,868	)		—		31,689
Net increase (decrease) in cash and cash equivalents		10,043			—			—			—		10,043
Cash and cash equivalents, beginning of period		8,165			—			—			—		8,165
Cash and cash equivalents, end of period	$	18,208		$	—		$	—		$	—	$	18,208

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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, 2011 as well as with the financial statements and related notes and the other information appearing elsewhere in this report. As used in this report, unless the context otherwise indicates, references to "we," "our," "ours," and "us" refer to Venoco, Inc. and its subsidiaries collectively.

Overview

        We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. Our strategy is to grow through exploration, exploitation and development projects we believe to have the potential to add significant reserves on a cost-effective basis and through selective acquisitions of underdeveloped properties. In recent years, the exploration, exploitation and development of the onshore Monterey shale formation has taken a fundamental role in our corporate strategy, and efforts to expand our knowledge of the onshore formation have increased significantly. In the execution of our strategy, our management is principally focused on economically developing additional reserves of oil and natural gas and on maximizing production levels through exploration, exploitation and development activities in a manner consistent with preserving adequate liquidity and financial flexibility.

Recent Events

        In August 2011, our board of directors received a proposal from our executive chairman and former CEO, Timothy Marquez, to acquire all of the outstanding shares of our common stock of which he was not the beneficial owner for $12.50 per share in cash. At the time of the proposal, Mr. Marquez was the beneficial owner of approximately 50.3% of the common stock. The board of directors formed a special committee comprised of all independent directors to evaluate and consider this proposal as well as third party alternatives. In January 2012, we announced that we had entered into a definitive merger agreement with Mr. Marquez and certain of his affiliates pursuant to which he would acquire all shares he did not beneficially own for $12.50 per share in cash, a transaction we refer to as the going private transaction. The special committee also announced that it unanimously concluded that the going private transaction was in the best interest of the Company's minority shareholders. As a result, the agreement was approved by the full board of directors, with Mr. Marquez abstaining. On June 5, 2012, the shareholders (including a majority of unaffiliated shareholders) approved the merger and on October 3, 2012, the transaction contemplated by the merger agreement was completed. As a result, Venoco's common stock is no longer publicly traded, however, the Company will continue as a voluntary filer with the SEC as required by the indentures governing our senior notes.

        In connection with the closing of the going private transaction, we entered into the fifth amended and restated credit agreement related to our revolving credit facility and a $315 million second lien term loan. Both of these agreements are discussed in further detail in "—Capital Resources and Requirements".

Capital Expenditures

        We have developed an active capital expenditure program to take advantage of our extensive inventory of drilling prospects and other projects. Our 2012 development, exploitation and exploration capital expenditure budget was initially set at $255 million, of which approximately $179.9 million has been incurred in the first nine months of 2012. However, in view of the closing of the going private transaction and the financial covenants included in our debt agreements following the closing (including

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covenants restricting certain capital expenditures in some circumstances), we expect to reduce our 2012 capital expenditures over the remainder of the year. We currently expect that we will end the year with capital spending of approximately $215 million, with approximately $109 million spent relating to Southern California legacy projects, $78 million spent on onshore Monterey projects and the remaining $28 million related to the Sacramento Basin. The reduced spending is expected to reflect an increased focus on development activities relative to exploration drilling. We are currently in the process of developing our 2013 capital budget. We currently expect that our capital expenditures in 2013 will likely be significantly below our 2012 capital expenditures, in part as a result of an expected reduction in drilling activities in the onshore Monterey shale.

        The aggregate levels of capital expenditures for the remainder of 2012 and 2013, and the allocation of those expenditures, are dependent on a variety of factors, including changes in commodity prices, permitting issues, 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 2012 capital spending program to date and the current outlook for the remainder of 2012.

Southern California—Exploitation and Development

        In the West Montalvo field, we have pursued an active workover, recompletion and return to production program that has resulted in significant production gains since we acquired the field in May 2007. Beginning in 2011, we began an active drilling program in the field and we continue to evaluate our drilling results and refine our development program for the coming years. During the first nine months of 2012, we spud four wells and completed six wells, including two wells that were spud in 2011. We do not plan to perform any additional drilling activity during the fourth quarter of 2012 at Montalvo. The field has not been fully delineated offshore or fully developed onshore.

        In the Sockeye field, we drilled three wells and performed one recompletion during the first nine months of the year. We do not expect to incur any significant capital expenditures at Sockeye during the fourth quarter.

        At the South Ellwood field, our plans include the drilling of four wells during 2012 (three PUDs and one probable well). We completed two of the PUD wells during the second quarter. The third PUD well was completed in the third quarter and was not successful. We expect to re-drill this well in the fourth quarter. The probable well was spud in the third quarter and will be completed in the first quarter of 2013.

        Our subsidiary Ellwood Pipeline, Inc. completed construction of a common carrier pipeline that allows us to transport our oil from the field to refiners without the use of a barge or the marine terminal we previously used. The pipeline commenced operations in January 2012.

Southern California—Onshore Monterey Shale

        In 2006, we began actively leasing onshore acreage in Southern California targeting the Monterey shale. Our leasing has focused on areas where we believe the Monterey shale will produce light, sweet oil, and where the quality and depth of the Monterey shale is expected to be advantageous. To date, our onshore Monterey shale acreage position totals approximately 240,000 gross and 170,000 net acres and is located primarily in three basins: Santa Maria, Salinas Valley and San Joaquin. We also have an additional 60,000 gross and 46,000 net acres with Monterey shale production or potential which are held by production at our legacy Southern California fields.

        Since 2010, we have pursued an active drilling program targeting the onshore Monterey shale formation. From that time through the third quarter of 2012, we have spud 29 wells and have set casing

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on 25 of those wells. We have been encouraged by the scientific information collected thus far, particularly in two of our prospect areas (the Sevier field in the San Joaquin Basin and the South Salinas field in the Salinas Valley), however, to date, we have not seen material levels of production or reserves from the program. Based on the data we have gathered and the results we have seen to date at the Sevier field, we believe that our testing efforts and delineation drilling in the area will ultimately result in commercial levels of production from the field.

        During the first nine months of 2012, we spud five wells at Sevier and also completed five wells including one well spud during the fourth quarter of 2011. For the full year 2012, we expect to incur approximately $78 million in capital expenditures related to onshore Monterey development, of which $66 million has been incurred during the first nine months of 2012. We originally planned to drill 15 to 20 wells at Sevier during the year. Currently, however, we do not plan to spud any additional wells in the fourth quarter in Sevier.

Sacramento Basin

        We have reduced our activity levels in the Sacramento Basin in recent years as a result of depressed natural gas prices and our increased focus on our oil-based projects including Monterey shale activities. For the full year 2012, we plan to drill four wells and perform over 200 recompletions. During the nine months of 2012, we spud three wells and performed 173 recompletions. We spud the fourth well early in the fourth quarter. Our reduced capital spending has resulted in lower average daily production in the first nine months of 2012 than our 2011 average daily production from the basin. We would expect to return to a focus on growth in the basin when natural gas prices improve. At that time we would expect to continue to pursue our infill drilling program in the greater Grimes and Willows fields and to test and evaluate potential downspacing opportunities in the basin as well as new methods of improving productivity and reducing drilling costs.

Acquisitions and Divestitures

        Sale of Santa Clara Avenue Field.    In May 2012, we sold our interests in the Santa Clara Avenue field for $23.4 million (after closing adjustments).

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

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, value of our proved reserves and borrowing capacity under our revolving credit facility, all of which depend in part upon those prices. The low natural gas price environment that existed at the end of 2011 has not substantially improved in the first nine months of 2012. If natural gas prices remain at depressed levels through the remainder of the year, certain of our proved undeveloped locations in the Sacramento Basin would become uneconomic based on SEC pricing and we would be required to remove the locations from our proved reserves at year-end. Our internal estimates of proved reserves as of September 30, 2012 reflect a significant reduction in proved undeveloped reserves in the Sacramento Basin. However, this reduction in estimated reserve quantities did not result in a significant change to the estimated PV-10 value of our company-wide proved reserves as of that date.

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        We employ a hedging strategy to reduce the variability of the prices we receive for our production and provide a minimum revenue stream. As of November 6, 2012, we had hedge contract floors covering 8,500 barrels of oil per day and 29.5 million cubic feet of natural gas per day for the remainder of 2012. We have also secured hedge contracts for portions of our 2013, 2014 and 2015 production. See "Quantitative and Qualitative Disclosures About Market Risk—Commodity Derivative Transactions" for further details concerning our hedging activities.

        Additionally, the sales contracts under which we have historically sold a significant portion of our oil were based on the NYMEX WTI ("WTI") crude price index and these contracts expired at the end of the first quarter of 2012. To replace the expiring contracts, we entered into new sales contracts based on certain Southern California crude price indexes, which traded at a premium to WTI throughout 2011 and the first nine months of 2012 and have more closely tracked with the Inter-Continental Exchange Brent crude price index ("Brent"). Additionally, effective February 2012, we entered into a new sales contract related to oil produced from our South Ellwood field with terms more favorable than the previous contract because, as of January 31, 2012, we were able to deliver our oil through a common carrier pipeline rather than via barge. As a result of these contracts, our average realized price for oil in the period from April through September 2012 was approximately $6.70 per barrel higher than the average WTI price and approximately $9.60 per barrel below the average Brent price for the same period.

        Expected Production.    As a result of higher oil prices and sustained depressed natural gas prices, we have emphasized our oil projects in Southern California relative to our natural gas projects in the Sacramento Basin in our 2012 capital expenditures budget. Our capital spending through nine months has been allocated approximately 52% to our legacy Southern California fields and 37% to our onshore Monterey shale program. As a result of the increase in capital spending related to our oil producing Southern California assets in 2012, our production ratio of oil to natural gas has increased in 2012 relative to 2011. We expect the ratio of oil to natural gas production to continue to increase during the fourth quarter and in 2013. We expect overall production in 2012 to be similar to production in 2011 on a BOE basis. Our expectations with respect to future production rates are subject to a number of uncertainties, including those associated with third party services, limitations on capital expenditures resulting from the terms of our debt agreements, the availability of drilling rigs, oil and natural gas prices, events resulting in unexpected downtime, permitting issues, drilling success rates, including our ability to identify productive intervals and the drilling and completion techniques necessary to achieve commercial production in the onshore Monterey shale on a broader scale, and other factors, including those referenced in the "Risk Factors" section of our Annual Report on Form 10-K for the year ended December 31, 2011.

        Lease Operating Expenses.    Lease operating expenses ("LOE") of $14.09 per BOE for the first nine months of 2012 were slightly lower than our full year 2011 results of $14.64 per BOE. We expect our 2012 LOE per BOE to be similar to 2011. Our expectations with respect to future expenses are subject to numerous risks and uncertainties, including those described and referenced in the preceding paragraph.

        Property and Production Taxes.    Property and production taxes of $1.79 per BOE for the first nine months of 2012 were higher than our full year 2011 results of $0.99 per BOE. We expect our 2012 property and production taxes to be higher on a per BOE basis compared to our 2011 results due primarily to supplemental ad valorem taxes related to successful oil wells drilled during 2012. As with lease operating expenses, our expectations with respect to future property and production taxes are subject to numerous risks and uncertainties.

        Transportation Expenses.    Transportation expenses were $1.08 per BOE for the first nine months of 2012 compared to $1.45 per BOE for the full year 2011. Because we now transport our South Ellwood

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oil via a common carrier onshore pipeline and have eliminated the use of the barge, we expect that our full year transportation expenses in 2012 will be lower than 2011 on both a dollar and a BOE basis.

        General and Administrative Expenses.    General and administrative expenses increased to $5.37 per BOE (excluding share-based compensation charges of $0.75 per BOE and costs of $0.99 per BOE related to the going private transaction) in the first nine months of 2012 compared to $4.96 per BOE for 2011 (excluding share-based compensation charges of $0.88 per BOE and costs of $0.26 per BOE related to the going private transaction). Excluding share-based compensation charges and going private related charges, on a per BOE basis, we expect our G&A costs to increase in 2012 compared to 2011. As with our lease operating expenses and property and production taxes, our expectations with respect to G&A costs are subject to numerous risks and uncertainties.

        Depreciation, Depletion and Amortization (DD&A).    DD&A for the first nine months of 2012 of $13.73 per BOE increased from our full year 2011 DD&A of $13.35 per BOE. We expect our 2012 DD&A to increase on a per BOE basis compared to our full year 2011 results. As with lease operating expenses, property and production taxes and G&A expenses, our expectations with respect to DD&A expenses are subject to numerous risks and uncertainties.

        Interest Expense.    In connection with the going private transaction, on October 3, 2012 we entered into a $315 million second lien term loan facility with an interest rate floor of 8.50% per annum. As a result of this additional debt, we expect interest expense for the full year 2012 to be higher than interest expense incurred in 2011.

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

        Income Tax Expense (Benefit).    We incurred losses before income taxes in 2008 and 2009 as well as taxable losses in each of the tax years from 2007 through 2011. These losses and expected future taxable losses were key considerations that led us to conclude that we should maintain a full valuation allowance against our net deferred tax assets at December 31, 2011 and September 30, 2012 since we could not conclude that it is more likely than not that the net deferred tax assets will be fully realized. As long as we continue to conclude that we have a need for a full valuation allowance against our net deferred tax assets, we likely will not have any income tax expense or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims or for state income taxes. Future events or new evidence which may lead us to conclude that it is more likely than not that our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings; consistent and sustained pre-tax earnings; sustained or continued improvements in oil and natural gas commodity prices; meaningful incremental oil production and proved reserves from development efforts at our Southern California legacy properties; consistent, meaningful production and proved reserves from our onshore Monterey shale project; meaningful production and proved reserves from the CO₂ project at the Hastings Complex; and taxable events resulting from one or more deleveraging transactions. We will continue to evaluate whether the valuation allowance is needed in future reporting periods.

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Results of Operations

        The following table reflects the components of our oil and natural gas production and sales prices and sets forth our operating revenues, costs and expenses on a BOE basis for the three and nine months ended September 30, 2011 and 2012. This information reflects the actual historical results of our operations. No pro forma adjustments have been made for acquisitions and divestitures of oil and gas properties, which will affect the comparability of the data below.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2012			2011			2012
Production Volume:
Oil (MBbls)(1)		594			839			1,821			2,172
Natural gas (MMcf)		5,966			4,846			17,812			15,688
MBOE		1,588			1,647			4,790			4,787
Daily Average Production Volume:
Oil (Bbls/d)		6,457			9,120			6,670			7,927
Natural gas (Mcf/d)		64,848			52,674			65,245			57,255
BOE/d		17,265			17,899			17,544			17,470
Oil Price per Bbl Produced (in dollars):
Realized price	$	87.24		$	96.20		$	90.06		$	98.26
Realized commodity derivative gain (loss)(2)		(5.01	)		(9.68	)		(3.97	)		(8.34	)
Net realized price	$	82.23		$	86.52		$	86.09		$	89.92
Natural Gas Price per Mcf (in dollars):
Realized price	$	4.18		$	2.86		$	4.16		$	2.67
Realized commodity derivative gain (loss)(2)		0.93			0.11			0.91			0.40
Net realized price	$	5.11		$	2.97		$	5.07		$	3.07
Expense per BOE:
Lease operating expenses	$	18.06		$	13.90		$	14.90		$	14.09
Property and production taxes		1.13			1.01			1.00			1.79
Transportation expenses		1.49			0.29			1.47			1.08
Depreciation, depletion and amortization		12.85			13.50			13.32			13.73
General and administrative expense(3)		5.82			7.18			5.82			7.11
Interest expense		10.08			10.02			9.33			10.05

(1)

Amounts shown are oil production volumes for offshore properties and sales volumes for onshore properties (differences between onshore production and sales volumes are minimal). Revenue accruals are adjusted for actual sales volumes since offshore oil inventories can vary significantly from month to month based on pipeline inventories, oil pipeline sales nominations, and prior to February 2012, the timing of barge deliveries and oil in tanks.

(2)

The realized commodity derivative gain (loss) excludes gains from the early settlement of oil and natural gas hedges in the following periods:

—nine months ended September 30, 2012 excludes gains of $44.3 million for natural gas and $7.9 million for oil.

—nine months ended September 30, 2011 excludes gain of $2.0 million for oil.

(3)

Net of amounts capitalized.

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Comparison of Quarter Ended September 30, 2012 to Quarter Ended September 30, 2011

        Oil and Natural Gas Sales.    Oil and natural gas sales increased $18.1 million (23%) in the third quarter of 2012 to $95.4 million compared to $77.3 million in the third quarter of 2011. Sales in the third quarter of 2012 were primarily impacted by higher oil production and higher oil prices compared to the third quarter of 2011, partially offset by lower natural gas prices and lower natural gas production in the third quarter of 2012, as described below.

        Oil sales increased by $29.1 million (56%) in the third quarter of 2012 to $81.5 million compared to $52.4 million in the third quarter of 2011. Oil production increased by 41%, with production of 839 MBbls in the third quarter of 2012 compared to 594 MBbls in the third quarter of 2011. The increase is primarily due to higher production at our South Ellwood and West Montalvo fields, resulting from successful drilling activity. Our average realized price for oil increased $8.96 per Bbl (10%) from $87.24 per Bbl in the third quarter of 2011 to $96.20 per Bbl for the third quarter of 2012. Our new sales contracts, which are tied to Southern California indices and were effective April 1, 2012, contributed to the higher average sales prices realized in the third quarter of 2012.

        Natural gas sales decreased $11.0 million (44%) in the third quarter of 2012 to $13.9 million compared to $24.9 million in the third quarter of 2011. Natural gas production decreased by 19% in the third quarter of 2012, with production of 4,846 MMcf compared to 5,966 MMcf in the third quarter of 2011. The decrease is primarily the result of (i) the natural production decline of wells in the Sacramento Basin and (ii) the limited number of new wells drilled during the latter part of 2011 and the first nine months of 2012 due to our reduced focus on natural gas projects resulting from the depressed natural gas price environment. Our average realized price for natural gas decreased $1.32 per Mcf (32%) from $4.18 per Mcf in the third quarter of 2011 to $2.86 per Mcf in the third quarter of 2012.

        Other Revenues.    Other revenues decreased $0.3 million (19%) in the third quarter of 2012 to $1.3 million compared to $1.6 million in the third quarter of 2011. During the third quarter of 2011, we received revenues related to sub-charter activity of the double-hulled barge used to transport oil production from our South Ellwood field. Our contract related to the barge was terminated effective in mid-May 2012; therefore, we did not realize any sub-charter revenue in the third quarter of 2012.

        Lease Operating Expenses.    Lease operating expenses ("LOE") decreased $5.8 million (20%) in the third quarter of 2012 to $22.9 million compared to $28.7 million in the third quarter of 2011. During the third quarter of 2011, we incurred increased LOE due primarily to (i) costs incurred to return Platform Grace to production, (ii) costs related to planned maintenance at Platform Holly and (iii) certain non-recurring maintenance performed at Dos Cuadras, Platform Gail and Platform Holly. Higher costs in the third quarter of 2011 were partially offset by an increase in costs incurred in connection with annual maintenance we performed at Platform Gail and Platform Grace in the third quarter of 2012. On a per unit basis, LOE decreased by $4.16 per BOE from $18.06 in the third quarter of 2011 to $13.90 in the third quarter of 2012.

        Property and Production Taxes.    Property and production taxes remained relatively consistent at $1.7 million in the third quarter of 2012 compared to $1.8 million in the third quarter of 2011. On a per BOE basis, property and production taxes decreased $0.12 per BOE to $1.01 in the third quarter of 2012 from $1.13 in the third quarter of 2011.

        Transportation Expenses.    Transportation expenses decreased $1.9 million (80%) to $0.5 million in the third quarter of 2012 compared to $2.4 million in the third quarter of 2011. Our contract related to the double-hulled barge which formerly transported oil produced from our South Ellwood field was terminated effective in mid-May 2012. We ceased using the barge to transport our oil in February because the onshore pipeline was completed. We incurred no significant costs related to the barge operation in the third quarter of 2012.

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        Depletion, Depreciation and Amortization (DD&A).    DD&A expense was relatively consistent at $22.2 million in the third quarter of 2012 compared to $20.4 million in the third quarter of 2011. DD&A expense on a per unit basis increased $0.65 per BOE to $13.50 per BOE for the third quarter of 2012 compared to $12.85 per BOE for the third quarter of 2011.

        Accretion of Abandonment Liability.    Accretion expense remained relatively constant at $1.5 million in the third quarter of 2012 compared to $1.6 million in the third quarter of 2011.

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

	Three Months Ended September 30,
	2011			2012
General and administrative costs	$	12,247		$	14,779
Share-based compensation costs		2,430			1,790
Going private related costs (none capitalized)		892			1,277
General and administrative costs capitalized		(6,333	)		(6,024	)
General and administrative expense	$	9,236		$	11,822

        G&A expenses increased $2.6 million (28%) to $11.8 million in the third quarter of 2012 from $9.2 million in the third quarter of 2011. The increase is primarily due to (i) higher payroll and legal costs incurred in the third quarter of 2012 and (ii) costs incurred related to the going private transaction. Excluding the effect of the non-cash share based compensation expense and going private related costs, G&A expense increased to $5.59 per BOE in the third quarter of 2012 from $4.43 per BOE in the third quarter of 2011.

        Interest Expense, Net.    Interest expense, net of interest income, was consistent between periods at $16.5 million in the third quarter of 2012 compared to $16.0 million in the third quarter of 2011.

        Amortization of Deferred Loan Costs.    Amortization of deferred loan costs was $0.6 million in both the third quarter of 2012 and the third quarter of 2011. The costs incurred relate to our loan agreements and are amortized over the estimated lives of the agreements.

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

	Three Months Ended September 30,
	2011			2012
Realized commodity derivative (gains) losses	$	(2,571	)	$	7,597
Amortization of commodity derivative premiums		1,990			1,203
Unrealized commodity derivative (gains) losses for changes in fair value		(37,991	)		40,289
Commodity derivative (gains) losses	$	(38,572	)	$	49,089

        Realized commodity derivative gains or losses represent the difference between the strike prices in the contracts settled during the period and the ultimate settlement prices. The realized commodity derivative losses in the third quarter of 2012 reflect the settlement of contracts at prices above the relevant strike prices, while the realized commodity gains in the third quarter of 2011 reflect the settlement of contracts below the relevant strike prices. Unrealized commodity derivative (gains) losses

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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).    Due to our valuation allowance, there was no income tax expense (benefit) recorded for the quarters ended September 30, 2012 or 2011. As long as we continue to conclude that we have a need for a full valuation allowance against our net deferred tax assets, we likely will not have any income tax expense or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims, or for state income taxes.

        Net Income (Loss).    Net loss for the third quarter of 2012 was $30.1 million compared to net income of $36.8 million for the same period in 2011. The change between periods is the result of the items discussed above.

Comparison of Nine Months Ended September 30, 2012 to Nine Months Ended September 30, 2011

        Oil and Natural Gas Sales.    Oil and natural gas sales increased $18.2 million (8%) to $259.7 million for the nine months ended September 30, 2012 from $241.5 million for the same period in 2011. During the first nine months of 2012, realized oil prices and oil production increased compared to the same period in 2011, while natural gas realized prices and production decreased, as described below.

        Oil sales increased by $50.6 million (30%) for the first nine months of 2012 to $217.9 million compared to $167.3 million in the first nine months of 2011. Oil production increased by 19%, with production of 2,172 MBbls in the first nine months of 2012 compared to 1,821 MBbls in the first nine months of 2011. The increase is primarily due to higher production at our South Ellwood and West Montalvo fields, resulting from successful drilling activity. Our average realized price for oil increased $8.20 per Bbl (9%) from $90.06 per Bbl in the first nine months of 2011 to $98.26 per Bbl for the first nine months of 2012. Our new sales contracts, which are tied to Southern California indices and were effective April 1, 2012, contributed to the higher average sales prices realized in the first nine months of 2012.

        Natural gas sales decreased $32.4 million (44%) in the first nine months of 2012 to $41.8 million compared to $74.2 million in the first nine months of 2011. Natural gas production decreased by 2,124 MMcf (12%) with production of 15,688 MMcf in the first nine months of 2012 compared to 17,812 MMcf in the first nine months of 2011. The production decrease is primarily the result of (i) the natural production decline of wells in the Sacramento Basin and (ii) the limited number of new wells drilled during the latter part of 2011 and the first nine months of 2012 resulting from our reduced focus on natural gas projects due to the depressed natural gas price environment. Our average realized price for natural gas decreased $1.49 per Mcf (36%) from $4.16 per Mcf in the first nine months of 2011 to $2.67 per Mcf in the first nine months of 2012.

        Other Revenues.    Other revenues increased $1.0 million (25%) in the first nine months of 2012 to $4.9 million compared to $3.9 million in the first nine months of 2011. The increase in other revenues is primarily due to tariff revenue received from third party usage of our onshore pipelines in 2012. Our contract related to the barge was terminated effective in mid-May 2012, therefore, we did not realize any sub-charter revenue after May 2012.

        Lease Operating Expenses.    Lease operating expenses ("LOE") decreased $4.0 million (5%) to $67.4 million in the first nine months of 2012 from $71.4 million in the first nine months of 2011. On a per unit basis, LOE decreased by $0.81 per BOE from $14.90 in the first nine months of 2011 to $14.09 in the first nine months of 2012. During the third quarter of 2011, we incurred increased LOE due primarily to costs incurred to return Platform Grace to production. Additionally, we incurred less

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non-recurring maintenance costs in the first nine months of 2012 compared to the first nine months of 2011.

        Property and Production Taxes.    Property and production taxes increased by $3.8 million (80%) in the first nine months of 2012 to $8.6 million compared to $4.8 million in the first nine months of 2011. The increase is primarily due to supplemental ad valorem taxes related to successful oil wells drilled during the second quarter of 2012. On a per BOE basis, property and production taxes increased $0.79 per BOE to $1.79 per BOE in the first nine months of 2012 from $1.00 per BOE in the first nine months of 2011.

        Transportation Expenses.    Transportation expenses decreased by $1.8 million (27%) to $5.2 million in the first nine months of 2012, compared to $7.0 million in the first nine months of 2011. The decrease was due to elimination, in mid-May 2012, of the barge operation which formerly transported oil produced from our South Ellwood field. The barge operation was eliminated as a result of the completion of the onshore pipeline during the first quarter of 2012.

        Depletion, Depreciation and Amortization (DD&A).    DD&A expense was relatively consistent between periods at $65.7 million in the first nine months of 2012 and $63.8 million in the first nine months of 2011. DD&A expense on a per unit basis also remained relatively consistent at $13.73 per BOE for the first nine months of 2012 compared to $13.32 per BOE for the first nine months of 2011.

        Accretion of Abandonment Liability.    Accretion expense was relatively consistent between periods at $4.3 million in the first nine months of 2012 and $4.8 million in the first nine months of 2011.

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

	Nine Months Ended September 30,
	2011			2012
General and administrative costs	$	39,520		$	43,176
Share-based compensation costs		7,140			5,850
Going private related costs (none capitalized)		892			4,757
General and administrative costs capitalized		(19,663	)		(19,731	)
General and administrative expense	$	27,889		$	34,052

        G&A expenses increased $6.2 million (22%) to $34.1 million in the first nine months of 2012 from $27.9 million in the first nine months of 2011. The increase is primarily due to costs incurred related to the going private transaction as well as increases in payroll costs, travel costs and professional and legal fees. Excluding the effect of the non-cash share based compensation expense and going private related costs, G&A expense increased to $5.37 per BOE in the first nine months of 2012 from $4.79 per BOE in the first nine months of 2011.

        Interest Expense, Net.    Interest expense, net of interest income, increased $3.4 million (8%) from $44.7 million in the first nine months of 2011 to $48.1 million in the first nine months of 2012. The increase was partially the result of the refinancing of our second lien term loan in February 2011 with the issuance of our 8.875% senior notes. The interest rate on our second lien term loan, which was outstanding for approximately one month during the first nine months of 2011, averaged approximately 4.5% per annum during that period. The increase is also due to a higher outstanding debt balance related to our revolving credit facility during the first nine months of 2012 compared to the same period in 2011.

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        Amortization of Deferred Loan Costs.    Amortization of deferred loan costs was $1.8 million in the first nine months of 2012 compared to $1.7 million in the first nine months of 2011. The costs incurred relate to our loan agreements and are amortized over the estimated lives of the agreements.

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

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

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

	Nine Months Ended September 30,
	2011			2012
Realized commodity derivative (gains) losses	$	(11,546	)	$	(40,285	)
Amortization of commodity derivative premiums		5,970			11,222
Unrealized commodity derivative (gains) losses for changes in fair value		(9,425	)		101,994
Commodity derivative (gains) losses	$	(15,001	)	$	72,931

        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 both the first nine months of 2012 and the first nine months of 2011 reflect the settlement of contracts at prices below the relevant strike prices. Additionally, we unwound certain oil and natural gas contracts in the first nine months of 2012 and realized a gain of $52.2 million which is reflected in realized commodity derivative (gains) losses. We also unwound certain oil swaps in the second quarter of 2011 and realized a gain of $2.0 million which is 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. We recognized derivative premium amortization expense of $7.6 million related to the contracts that were unwound during the first nine months of 2012. There was no premium associated with the contracts that were unwound in 2011.

        Income Tax Expense (Benefit).    Due to our valuation allowance, there was no income tax expense (benefit) recorded for the nine months ended September 30, 2012 or 2011. As long as we continue to conclude that we have a need for a full valuation allowance against our net deferred tax assets, we likely will not have any income tax expense or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims, or for state income taxes.

        Net Income (Loss).    Net loss for the first nine months of 2012 was $43.4 million compared to net income of $31.9 million for the same period in 2011. The change between periods is the result of the items discussed above.

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Liquidity and Capital Resources

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

Cash Flows

	Nine Months Ended September 30,
	2011			2012
	(in thousands)
Cash provided by operating activities	$	66,568		$	134,320
Cash (used in) provided by investing activities		(190,768	)		(155,966	)
Cash (used in) provided by financing activities		119,185			31,689

        Net cash provided by operating activities was $134.3 million in the first nine months of 2012 compared to $66.6 million in the 2011 period. Cash flows from operating activities in the first nine months of 2012 as compared to the 2011 period were favorably impacted by the realized gain of $52.2 million from the early settlement of oil and natural gas derivative contracts, higher realized oil prices and higher oil production, partially offset by lower natural gas prices and lower natural gas production. The first nine months of 2011 was unfavorably impacted by the settlement of our interest rate derivative contracts in the first quarter of 2011 for $38.1 million.

        Net cash used in investing activities was $156.0 million in the first nine months of 2012 compared to $190.8 million in the 2011 period. The primary investing activities in the first nine months of 2012 were $176.7 million in capital expenditures on oil and natural gas properties related to our capital expenditure program, partially offset by $23.4 million in net cash proceeds received from the sale of our Santa Clara Avenue field in the second quarter of 2012. The primary investing activities in the first nine months of 2011 were $189.5 million in capital expenditures on oil and natural gas properties related to our capital expenditure program.

        Net cash provided by financing activities was $31.7 million in the first nine months of 2012 compared to $119.2 million during the 2011 period. The primary financing activities in the first nine months of 2012 were $32 million in net borrowings under our revolving credit facility. The primary financing activities in the first nine months of 2011 were related to two capital raising transactions we completed during the period. First, we issued 4.6 million shares of common stock at a price to the public of $18.75 per share. We received net proceeds of approximately $82.2 million from the equity offering after deducting offering-related expenses. Second, we issued $500 million of 8.875% senior unsecured notes which are due in February 2019. We received net proceeds of approximately $490.3 million from the notes offering, after deducting offering-related expenses. The proceeds from the two transactions were used to repay the outstanding principal of $455.3 million and accrued interest of $1.6 million related to our second lien term loan, settle the related interest rate swap contracts for $38.1 million as described above and repay the then outstanding balance of $45.0 million on our revolving credit facility.

Capital Resources and Requirements

        We plan to make substantial capital expenditures in the future for the acquisition, exploration, exploitation and development of oil and natural gas properties. Our 2012 exploration, exploitation and development capital expenditures are expected to be approximately $215 million and through the first nine months of 2012, we have incurred $179.9 million related to capital expenditures. Although we have not yet finalized our 2013 capital budget, we expect the budget will likely be significantly below our 2012 capital expenditure level. We expect to fund the remainder of our 2012 and our 2013 capital expenditures primarily with cash flow from operations, supplemented with borrowings under our

43

revolving credit facility. We have significant flexibility to reduce capital expenditures if warranted by business conditions or limits on our capital resources. Uncertainties relating to our capital resources and requirements include the possibility that one or more of the counterparties to our hedging arrangements may fail to perform under the contracts, the effects of changes in commodity prices and differentials, results from our onshore Monterey shale program, which could lead us to accelerate or decelerate activities depending on the extent of our success in developing the program, and the possibility that we will pursue one or more significant acquisitions that would require additional debt or equity financing. As described below, the terms of our debt agreements contain certain financial covenants, including financial covenants that limit certain capital expenditures in some circumstances. The amount and nature of our future capital expenditures will be affected by these covenants. Among other things, we expect to reduce our focus on activities targeting the onshore Monterey shale in 2013. We expect to pursue one or more deleveraging transactions in 2012 or 2013, which may include the formation of a master limited partnership, asset sales, joint ventures or other transactions. There can be no assurance that any such transaction can be completed in the time frame we expect or at all.

        Revolving Credit Facility.    In October 2012, we entered into a fifth amended and restated credit agreement governing our revolving credit facility, which has a maturity date of March 31, 2016. The agreement contains customary representations, warranties, events of default, indemnities and covenants, including covenants that restrict our ability to incur indebtedness and require us to maintain specified ratios of current assets to current liabilities, debt to EBITDA and interest coverage. The agreement also limits the amount of exploratory capital spending we can incur on our onshore Monterey program if our debt to EBITDA ratio exceeds 3.75 to 1.00. The minimum ratio of current assets to current liabilities (as those terms are defined in the agreement) is 1.00 to 1.00; the maximum ratio of debt to EBITDA (as defined in the agreement) is 5.00 to 1.00 through March 31, 2013 and steps down to 4.00 to 1.00 by September 30, 2014; the minimum interest coverage ratio (as defined in the agreement) is 1.75 to 1.00. As a result of the additional debt incurred in connection with the going private transaction and the associated financial covenants that step down over time, 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 drilling results that are less favorable than anticipated, lower realized commodity prices, 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) the administrative agent's announced base rate, (y) the federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.0%, plus (ii) an applicable margin ranging from 1.25% to 2.00%, 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. The applicable margin for both Base Rate Loans and LIBO Rate Loans will be increased by 0.50% in the event that our debt to EBITDA ratio exceeds 3.75 to 1.00 on the last day of each of the two fiscal quarters most recently ended. A commitment fee of 0.50% per annum is payable with respect to unused borrowing availability under the facility.

        The revolving credit facility has a total capacity of $500.0 million, but is limited by the lesser of commitments from participating lenders of $156.0 million and our borrowing base which is currently established at $175.0 million. The borrowing base is subject to redetermination twice each year, and may be redetermined at other times at our request or at the request of the lenders. Lending commitments under the facility have been allocated at various percentages to a syndicate of eight banks. Certain of the institutions included in the syndicate have received support from governmental agencies in connection with events in the credit markets. A failure of any members of the syndicate to fund under the facility, or a reduction in the borrowing base, would adversely affect our liquidity. As of

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November 6, 2012, we had $101.0 million outstanding under the facility and $51.2 million in available borrowing capacity, net of the outstanding balance and $3.8 million of outstanding letters of credit.

        Second Lien Term Loan.    In connection with the going private transaction, we entered into a $315.0 million senior secured second lien term loan agreement in October 2012. The agreement contains certain customary covenants, including covenants that restrict the Company's ability to incur additional indebtedness and financial covenants that require the Company to maintain specified ratios of debt to adjusted EBITDA, interest coverage and collateral coverage. Under the terms of the agreement, we are restricted with respect to the amount of exploratory capital expenditures we can incur related to our onshore Monterey project when our debt to EBITDA ratio exceeds 5.0 to 1.0. Additionally, the agreement requires us to maintain defined levels of derivative contracts for a three year period. We cannot, however, enter into derivative contracts (other than certain put contracts) covering more than 80% of projected oil and gas production in any month. In addition, we are required 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.

        Loans made under the second lien term loan facility are designated, at our 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 (x) the administrative agent's announced prime rate, (y) the federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.0%, plus (ii) 6.00%. Loans designated as LIBO Rate Loans bear interest at LIBOR plus 7.00%. Per the Second Lien Term Loan Agreement, LIBOR shall not be less than 1.50%.

        8.875% Senior Notes.    In February 2011, we issued $500 million in 8.875% senior unsecured notes due in February 2019 at par. Concurrently with the sale of the 8.875% senior notes, we repaid in full the outstanding principal balance of $455.3 million on our then outstanding second lien term loan. The 8.875% senior notes pay interest semi-annually in arrears on February 15 and August 15 of each year. We may redeem the notes prior to February 15, 2015 at a "make whole premium" defined in the indenture. Beginning February 15, 2015, we may redeem the notes at a redemption price of 104.438% of the principal amount and declining to 100% by February 15, 2017. The 8.875% senior notes are senior unsecured obligations and contain operational covenants that, among other things, limit our ability to make investments, incur additional indebtedness or create liens on our assets.

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

        Because we must dedicate a substantial portion of our cash flow from operations to the payment of amounts due under our debt agreements, that portion of our cash flow is not available for other purposes. Our ability to make scheduled interest payments on our indebtedness, maintain compliance with the covenants in our debt agreements 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 while also allowing us to maintain compliance with our debt agreements, 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

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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 debt agreements, 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 agreements that require us to use some or all of the proceeds of such transactions to reduce amounts outstanding under the agreements 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. The additional indebtedness we incurred as a result of the closing of the going-private transaction has increased the debt-related risks we face as described in our Annual Report on Form 10-K for the year ended December 31, 2011, including the risks that we may default on our obligations under our debt agreements, that our ability to replace our reserves and maintain our production may be adversely affected by capital constraints and the financial covenants under our debt agreements and that we may be more vulnerable to adverse changes in commodity prices and other economic conditions.

Environmental Regulations

        In our Annual Report on Form 10-K, we discussed recent and future environmental regulations, including California's Assembly Bill (AB) 32, known as "California Global Warming Solutions Act of 2006", which establishes a "cap and trade" program. The California Air Resources Board adopted regulations that went into effect on January 1, 2012. The California Air Resources Board is expected to issue an allocation of allowances applicable to our emissions, at which point we will be able to determine the extent of additional allowances that we will need to acquire in the marketplace to cover emissions related to our operations. Until the allowance allocation is published, we are not able to determine the extent of the impact on our operations; however, we do not expect the impact to be significant.

Off-Balance Sheet Arrangements

        At September 30, 2012, we had no existing off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Item 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

        This section also provides information about our interest rate risk. See "—Interest Rate Risk."

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Commodity Derivative Transactions

        Commodity Derivative Agreements.    As of September 30, 2012, we had entered into various swap, collar and option agreements related to our oil and natural gas production. The aggregate economic effects of those agreements are summarized below. Location and quality differentials attributable to our properties are not included in the following prices. The agreements provide for monthly settlement based on the differential between the agreement price and the price per the applicable index (WTI (oil), Brent (oil) or NYMEX Henry Hub (natural gas)).

	Oil (NYMEX WTI)				Oil (Brent)				Natural Gas (NYMEX Henry Hub)
	Barrels/day		Weighted Avg. Prices per Bbl		Barrels/day		Weighted Avg. Prices per Bbl		MMBtu/day		Weighted Avg. Prices per MMBtu
October 1 - December 31, 2012:
Swaps		—	$	—		—	$	—		29,500	$	3.00
Collars(1)		6,500	$	80.00/$118.15		—	$	—		—	$	—
Puts(1)		2,000	$	60.00		—	$	—		—	$	—
January 1 - December 31, 2013:
Swaps		—	$	—		—	$	—		24,000	$	3.47
Collars		—	$	—		4,600	$	90.00/$102.47		—	$	—
January 1 - December 31, 2014:
Swaps		—	$	—		—	$	—		18,600	$	3.82
Collars		—	$	—		4,100	$	90.00/$98.59		—	$	—
January 1 - December 31, 2015:
Collars		—	$	—		3,675	$	90.00/$98.95		15,000	$	3.50/$4.66

(1)

Reflects the impact of call spreads, purchased calls and sold puts, which are transactions we entered into for the purpose of modifying or eliminating the ceiling (or call) portion of certain collar arrangements.

        We have also entered into certain oil and natural gas basis swaps. The oil basis swaps fix the differential between the WTI crude price index and the Brent crude price index. Historically the two price indexes have demonstrated a close correlation with each other and with the Southern California indexes on which we sell a significant percentage of our oil. However, the relationship between WTI and Brent has diverged, favoring Brent crude. The Southern California indexes most relevant to us have tracked more closely with Brent prices than with WTI. The oil basis swaps we have entered into attempt to fix the current premium Southern California indexes are realizing relative to WTI. The natural gas basis swaps fix the differential between the Henry Hub price and the PG&E Citygate price, the index on which the majority of our natural gas is sold. Our oil and natural gas basis swaps as of September 30, 2012 are presented below:

	Oil Basis Swaps (NYMEX WTI)						Natural Gas Basis Swaps (NYMEX Henry Hub)
	Floating Index		Weighted Avg. Bbls/Day		Weighted Avg. Basis Differential to NYMEX WTI (per Bbl)		Floating Index		Weighted Avg. MMBtu/Day		Weighted Avg. Basis Differential to NYMEX HH (per MMBtu)
Basis Swaps:
October 1 - December 31, 2012		Brent Crude		8,500	$	6.82		—		—	$	—
January 1 - December 31, 2013		Brent Crude		3,900	$	5.88		PG&E Citygate		24,000	$	0.24
January 1 - December 31, 2014		—		—	$	—		PG&E Citygate		18,600	$	0.24
January 1 - December 31, 2015		—		—	$	—		PG&E Citygate		15,000	$	0.24

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Portfolio of Derivative Transactions

        Our portfolio of commodity derivative transactions as of September 30, 2012 is summarized below:

Oil

Type of Contract	Counterparty	Basis	Quantity (Bbl/d)		Strike Price ($/Bbl)		Term
Collar	RBS	NYMEX		3,000	$	60.00/$121.10		Oct 1 - Dec 31, 12
*Call (purchased)	Bank of Montreal	NYMEX		2,000	$	121.10		Oct 1 - Dec 31, 12
*Collar	Bank of Montreal	NYMEX		1,500	$	80.00/$110.85		Oct 1 - Dec 31, 12
*Collar	Bank of Montreal	NYMEX		1,000	$	85.00/$120.30		Oct 1 - Dec 31, 12
Collar	Bank of Nova Scotia	NYMEX		1,000	$	85.00/$120.10		Oct 1 - Dec 31, 12
*Collar	BNP Paribas	NYMEX		2,000	$	85.00/$120.10		Oct 1 - Dec 31, 12
Basis Swap	Bank of Montreal	NYMEX/Brent		2,950	$	7.28		Oct 1 - Dec 31, 12
Basis Swap	Bank of Montreal	NYMEX/Brent		550	$	7.15		Oct 1 - Dec 31, 12
Basis Swap	Bank of Montreal	NYMEX/Brent		2,750	$	6.90		Oct 1 - Dec 31, 12
Basis Swap	Bank of Montreal	NYMEX/Brent		2,250	$	6.05		Oct 1 - Dec 31, 12
Collar	Credit Suisse	ICE Brent		1,000	$	90.00/$98.00		Jan 1 - Dec 31, 13
Collar	Bank of America	ICE Brent		1,000	$	90.00/$101.25		Jan 1 - Dec 31, 13
Collar	Bank of Nova Scotia	ICE Brent		1,675	$	90.00/$98.15		Jan 1 - Dec 31, 13
Collar	Bank of Nova Scotia	ICE Brent		700	$	90.00/$122.70		Jan 1 - Dec 31, 13
Collar	Key Bank	ICE Brent		225	$	90.00/$97.00		Jan 1 - Dec 31, 13
Basis Swap	Bank of Montreal	NYMEX/Brent		2,470	$	6.05		Jan 1 - Dec 31, 13
Basis Swap	Bank of Montreal	NYMEX/Brent		1,000	$	5.80		Jan 1 - Dec 31, 13
Basis Swap	Bank of Montreal	NYMEX/Brent		430	$	5.10		Jan 1 - Dec 31, 13
Collar	Credit Suisse	ICE Brent		1,000	$	90.00/$98.00		Jan 1 - Dec 31, 14
Collar	Bank of America	ICE Brent		1,000	$	90.00/$101.25		Jan 1 - Dec 31, 14
Collar	Bank of Nova Scotia	ICE Brent		1,675	$	90.00/$98.15		Jan 1 - Dec 31, 14
Collar	Key Bank	ICE Brent		200	$	90.00/$93.75		Jan 1 - Dec 31, 14
Collar	Key Bank	ICE Brent		225	$	90.00/$97.00		Jan 1 - Dec 31, 14
Collar	Credit Suisse	ICE Brent		1,000	$	90.00/$98.00		Jan 1 - Dec 31, 15
Collar	Bank of America	ICE Brent		1,000	$	90.00/$101.25		Jan 1 - Dec 31, 15
Collar	Bank of Nova Scotia	ICE Brent		1,675	$	90.00/$98.15		Jan 1 - Dec 31, 15

Natural Gas

Type of Contract	Counterparty	Basis	Quantity (MMBtu/d)		Strike Price ($/MMBtu)		Term
Swap	Credit Suisse	NYMEX		17,500	$	3.00		Oct 1 - Dec 31, 12
Swap	Key Bank	NYMEX		12,000	$	3.00		Oct 1 - Dec 31, 12
Swap	Key Bank	NYMEX		24,000	$	3.47		Jan 1 - Dec 31, 13
Basis Swap	Credit Suisse	NYMEX/PG&E		24,000	$	0.24		Jan 1 - Dec 31, 13
Swap	Credit Suisse	NYMEX		12,500	$	3.82		Jan 1 - Dec 31, 14
Swap	Bank of Nova Scotia	NYMEX		6,100	$	3.81		Jan 1 - Dec 31, 14
Basis Swap	Credit Suisse	NYMEX/PG&E		12,600	$	0.24		Jan 1 - Dec 31, 14
Basis Swap	Key Bank	NYMEX/PG&E		6,000	$	0.24		Jan 1 - Dec 31, 14
Collar	Bank of America	NYMEX		15,000	$	3.50/$4.66		Jan 1 - Dec 31, 15
Basis Swap	Credit Suisse	NYMEX/PG&E		9,000	$	0.24		Jan 1 - Dec 31, 15
Basis Swap	Key Bank	NYMEX/PG&E		6,000	$	0.24		Jan 1 - Dec 31, 15

*

In October, we novated certain of our oil contracts previously held by Bank of Montreal and BNP Paribas to Citibank N.A.

        Subsequent to September 30, 2012, we entered into the following oil derivative contracts.

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Oil

Type of Contract	Counterparty	Basis	Quantity (Bbl/d)		Strike Price ($/Bbl)		Term
Swap	Citibank N.A.	ICE Brent		675	$	106.53		Jan 1 - Dec 31, 13
Swap	Bank of Nova Scotia	ICE Brent		675	$	106.50		Jan 1 - Dec 31, 13

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

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

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

        All derivative instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date. Changes in the fair value of derivatives are recorded in commodity derivative (gains) losses on the consolidated statement of operations. As of September 30, 2012, the fair value of our commodity derivatives was a net liability of $54.0 million.

Interest Rate Risk

        We are subject to interest rate risk with respect to amounts borrowed under our second lien term loan and from time to time under our revolving credit facility because those amounts bear interest at variable rates. The interest rates associated with our senior notes are fixed for the term of the notes. A 1.0% increase in interest rates would have resulted in additional annualized interest expense of

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$0.8 million on our variable rate borrowings of $75.0 million related to our revolving credit facility as of September 30, 2012.

        See notes to our consolidated financial statements for a discussion of our long-term debt as of September 30, 2012.

Item 4.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

        Our management, with the participation of Edward O'Donnell, our Chief Executive Officer, and Timothy Ficker, our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2012. Based on the evaluation, those officers believe that:

•

our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms; and

•

our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 was accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Internal Control Over Financial Reporting

        As a result of the going private transaction, all of the independent members of the board of directors ceased to be directors as of the closing of the transaction pursuant to the terms of the merger agreement. The audit committee was comprised of three independent board members, therefore, subsequent to October 3, 2012, we did not have an audit committee. While in existence, our audit committee performed an oversight role with respect to our financial reporting. However, we do not believe that the absence of the audit committee has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting for the quarterly period ended September 30, 2012. We are currently in the process of evaluating the need for and the composition of an audit committee comprised of independent directors.

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PART II—OTHER INFORMATION

Item 1.    LEGAL PROCEEDINGS

        The information set forth in the financial statements included in this report is incorporated by reference herein.

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, 2011, which could materially affect our business, financial condition and/or future results. The risks described in this report and 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.    MINE SAFETY DISCLOSURES

        Not Applicable

Item 5.    OTHER INFORMATION

        Not Applicable

Item 6.    EXHIBITS

Exhibit Number		Exhibit
	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.
	101	The following financial information from the quarterly report on Form 10-Q of Venoco, Inc. for the quarter ended September 30, 2012, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Changes in Stockholders' Equity, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements.

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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.

November 7, 2012

VENOCO, INC.
By:	/s/ EDWARD J. O'DONNELL
	Name:	Edward J. O'Donnell
	Title:	Chief Executive Officer
By:	/s/ TIMOTHY A. FICKER
	Name:	Timothy A. Ficker
	Title:	Chief Financial Officer

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