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 o NO ý

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.

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

On October 3, 2012, the issuer completed a going private transaction as a result of which its common stock is currently held by a single stockholder and was deregistered under the Securities Exchange Act of 1934.

This report on Form 10-Q contains forward-looking statements. 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, 2012. 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, 2012 and such things as:

PART I—FINANCIAL INFORMATION

VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(In thousands, except shares)

	December 31, 2012			June 30, 2013

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	53,818		$	3,516
Accounts receivable		108,356			26,694
Inventories		5,101			5,344
Other current assets		4,448			2,833
Commodity derivatives		153			2,128

Total current assets		171,876			40,515

PROPERTY, PLANT AND EQUIPMENT, AT COST:
Oil and gas properties, full cost method of accounting
Proved		1,927,259			1,935,596
Unproved		16,165			15,653
Accumulated depletion		(1,311,898	)		(1,334,369	)

Net oil and gas properties		631,526			616,880
Other property and equipment, net of accumulated depreciation and amortization of $15,176 and $15,302 at December 31, 2012 and June 30, 2013, respectively		17,076			16,832

Net property, plant and equipment		648,602			633,712

OTHER ASSETS:
Commodity derivatives		—			478
Deferred loan costs		21,569			14,810
Other		4,034			5,689

Total other assets		25,603			20,977

TOTAL ASSETS	$	846,081		$	695,204

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt	$	104,494		$	—
Accounts payable and accrued liabilities		57,315			40,677
Interest payable		27,862			21,326
Commodity derivatives		20,607			2,359
Share-based compensation		10,424			15,305

Total current liabilities		220,702			79,667

LONG-TERM DEBT		849,190			828,145
COMMODITY DERIVATIVES		20,287			3,137
ASSET RETIREMENT OBLIGATIONS		41,119			34,626
SHARE-BASED COMPENSATION		10,441			8,298

Total liabilities		1,141,739			953,873

COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Common stock, $.01 par value (200,000,000 shares authorized; 29,936,378 shares issued and outstanding at December 31, 2012 and June 30, 2013)		299			299
Additional paid-in capital		124,358			124,349
Retained earnings (accumulated deficit)		(420,315	)		(383,317	)

Total stockholders' equity		(295,658	)		(258,669	)

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	846,081		$	695,204

VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(In thousands)

	Three Months Ended June 30,						Six Months Ended June 30,

	2012			2013			2012			2013
REVENUES:
Oil and natural gas sales	$	80,936		$	81,449		$	164,324		$	167,408
Other		1,563			910			3,538			2,214

Total revenues		82,499			82,359			167,862			169,622
EXPENSES:
Lease operating expense		20,093			17,914			44,543			36,445
Property and production taxes		5,302			1,407			6,917			2,534
Transportation expense		257			45			4,669			83
Depletion, depreciation and amortization		21,213			12,406			43,467			23,978
Accretion of asset retirement obligations		1,450			615			2,841			1,271
General and administrative, net of amounts capitalized		9,869			10,375			22,230			25,350

Total expenses		58,184			42,762			124,667			89,661

Income from operations		24,315			39,597			43,195			79,961
FINANCING COSTS AND OTHER:
Interest expense, net		15,880			17,401			31,591			36,255
Amortization of deferred loan costs		585			906			1,154			2,019
Loss on extinguishment of debt		—			—			—			21,297
Commodity derivative losses (gains), net		(6,696	)		(19,951	)		23,842			(16,608	)

Total financing costs and other		9,769			(1,644	)		56,587			42,963

Income (loss) before income taxes		14,546			41,241			(13,392	)		36,998
Income tax provision (benefit)		—			—			—			—

Net income (loss)	$	14,546		$	41,241		$	(13,392	)	$	36,998

VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

(UNAUDITED)

(In thousands)

VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In thousands)

	Six Months Ended June 30,

	2012			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(13,392	)	$	36,998
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization		43,467			23,978
Accretion of asset retirement obligations		2,841			1,271
Share-based compensation		2,748			—
Amortization of deferred loan costs		1,154			2,019
Loss on extinguishment of debt		—			21,297
Amortization of bond discounts and other		371			574
Unrealized commodity derivative (gains) losses and amortization of premiums		71,724			(36,357	)
Changes in operating assets and liabilities:
Accounts receivable		1,775			8,845
Inventories		596			(243	)
Other current assets		1,608			1,502
Other assets		(2,308	)		(1,655	)
Accounts payable and accrued liabilities		333			(19,978	)
Share-based compensation liabilities		—			2,738
Net premiums paid on derivative contracts		(10,986	)		(1,494	)

Net cash provided by (used in) operating activities		99,931			39,495

CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties		(132,039	)		(45,516	)
Acquisitions of oil and natural gas properties		(235	)		(40	)
Expenditures for drilling equipment		—			(1,644	)
Expenditures for other property and equipment		(1,211	)		(363	)
Proceeds from sale of oil and natural gas properties		23,368			100,332

Net cash provided by (used in) investing activities		(110,117	)		52,769

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		140,000			294,900
Principal payments on long-term debt		(138,000	)		(426,900	)
Premium paid to pay down debt		—			(9,450	)
Payments for deferred loan costs		(93	)		(1,107	)
Proceeds from stock incentive plans and other		133			—
Going private share repurchase costs		—			(9	)

Net cash provided by (used in) financing activities		2,040			(142,566	)

Net (decrease) increase in cash and cash equivalents		(8,146	)		(50,302	)
Cash and cash equivalents, beginning of period		8,165			53,818

Cash and cash equivalents, end of period	$	19		$	3,516

Supplemental Disclosure of Cash Flow Information—
Cash paid for interest	$	31,764		$	42,217
Cash paid (received) for income taxes	$	—		$	—
Supplemental Disclosure of Noncash Activities—
(Decrease) increase in accrued capital expenditures	$	(1,659	)	$	(3,197	)

VENOCO, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Description of Operations Venoco, Inc. ("our," "us," "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 March 28, 2013, the Company entered into an amendment to its revolving credit agreement pursuant to which, among other things, certain financial covenants were changed and the borrowing base increased from $175 million to $270 million. The Company borrowed an additional $107 million under the facility and used those funds to repay all amounts outstanding under its second lien term loan facility. Details regarding each of the agreements are provided in the long-term debt footnote.

Liquidity The Company was in compliance with all debt covenants at June 30, 2013. However, the additional indebtedness that the Company incurred in connection with the going private transaction and the associated financial covenants that step down over time has increased debt-related risks. These include risks that the Company may default on its obligations under its debt agreements, that its ability to replace reserves and maintain its production may be adversely affected by capital constraints and the financial covenants under its debt agreements and that the Company may be more vulnerable to adverse changes in commodity prices and other operational risks and economic conditions. The Company recently amended its revolving credit facility to include more favorable financial covenant requirements in future periods. The Company believes that it will be in compliance with its amended debt covenants in the next four quarters. However, the Company currently projects that the margin by which it will be in compliance with certain covenants, particularly the debt-to-EBITDA covenant in its revolving credit agreement, will narrow as of September 30, 2013 and December 31, 2013. Due to various operational risks and commodity pricing risks, there can be no assurances that the Company will remain in compliance with this covenant or other covenants in its debt agreements.

In addition, the Company's sole stockholder, Denver Parent Corporation ("DPC") incurred $60 million of indebtedness in connection with the completion of the going private transaction. That indebtedness is secured by a pledge of all of the common stock of Venoco. If a default occurred and the lenders foreclosed on that stock, a change of control of Venoco would likely occur. Such a change of control could constitute an event of default under our revolving credit facility, and could obligate us to make an offer to purchase the Company's senior notes at a price equal to 101% of the principal amount of the notes plus accrued and unpaid interest. In that circumstance, the Company may not be able to obtain sufficient funds to satisfy its obligations under the revolving credit agreement and the notes indentures in a timely manner or at all. DPC recently amended its debt agreement to include more favorable financial covenant requirements in future periods which are generally similar to, but less restrictive than, those contained in the Company's revolving credit facility.

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, 2012 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 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, 2012 of $394.5 million for federal income tax purposes as a result of losses incurred before income taxes in 2008, 2009 and 2012 as well as taxable losses in each of the tax years from 2007 through 2012. These losses and expected future taxable losses were key considerations that led the Company to provide a full valuation allowance against its net deferred tax assets at December 31, 2012 and June 30, 2013 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.

Recently Issued Accounting Standards 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 did not have an impact on the Company's financial position or results of operations, other than enhanced disclosures regarding its derivative instruments.

In February 2013, the FASB issued Accounting Standards Update No. 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date ("ASU 2013-04"). The objective of ASU 2013-04 is to provide guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date. ASU 2013-04 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this standard will not have a significant impact on the Company's consolidated financial statements.

Sale of Sacramento Basin and San Joaquin Valley Assets. On December 31, 2012, the Company completed the sale of certain properties in the Sacramento Basin and San Joaquin Valley areas of California to an unrelated third party pursuant to a purchase and sale agreement executed on December 21, 2012. The total purchase price for the properties was $250 million, subject to certain closing adjustments, of which $100.6 million was placed into escrow pending the receipt of consents to assign and the expiration or waiver of preferential purchase rights relating to certain of the properties. All of the $100.6 million placed into escrow has been released to the Company as of June 30, 2013. The Company applied proceeds from the sale to pay down $214.7 million of the principal balance outstanding on its second lien term loan facility and to pay $6.4 million in prepayment penalties. 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.

Sale of Santa Clara Avenue. 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.

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

Revolving Credit Facility. In March 2013, the Company entered into an amendment to the fifth amended and restated credit agreement which maintained the maximum size of its revolving credit facility at $500 million and the maturity date of the facility at March 31, 2016. With the amendment, the borrowing base, which 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, was increased from $175 million to $270 million. Also, certain financial covenants were changed. The availability under the facility is limited to the commitments of the participating lenders, which total $268 million. The Company borrowed an additional $107 million under the facility contemporaneously with entering into the amendment, and used those funds to repay all amounts outstanding under the second lien term loan. The credit facility is secured by a first priority lien on substantially all of the Company's oil and natural gas properties and other assets, including the equity interests in all of the Company's subsidiaries, and is unconditionally guaranteed by each of the Company's 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, secured 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 banks. As of August 1, 2013, the Company had $173.0 million outstanding on the facility and had available borrowing capacity of $91.4 million under the facility, net of the outstanding balance and $3.6 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. The Company repaid $214.7 million of the outstanding principal amount under the facility, and $6.4 million in prepayment penalties, in the first quarter of 2013 with proceeds from the Sacramento Basin asset sale. In March 2013, it used $107 million of additional borrowings under the revolving credit facility to repay all remaining amounts outstanding under the facility and $3.0 million in prepayment penalties. Loans made under the second lien term loan facility were designated, at the Company's option, as either "Base Rate Loans" or "LIBO Rate Loans." Loans designated as Base Rate Loans bore interest at a floating rate equal to (i) the greater of (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 bore interest at LIBOR plus 7.00%. Per the second lien term loan agreement, LIBOR was to be not less than 1.50%.

The agreement governing the second lien term loan facility contained customary representations, warranties, events of default, covenants and indemnities. The facility was secured by second priority liens on substantially all of the Company's oil and natural gas properties and other assets, including the equity interests in all of its subsidiaries, and was unconditionally guaranteed by each of the Company's subsidiaries other than Ellwood Pipeline, Inc.

As noted above, the Company repaid a portion of amounts outstanding under the second lien term loan facility in the first quarter of 2013 with proceeds from the Sacramento Basin asset sale. The current portion of long-term debt of $104.5 million at December 31, 2012 reflects the principal amounts that the Company was required to repay on the facility from the sale proceeds that the Company received on December 31, 2012 and January 2, 2013, less the portion that the Company repaid with additional borrowings on the revolving credit facility.

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,

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.

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 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 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 June 30, 2013, the balance of unamortized net derivative premiums paid was $10.5 million, of which $2.0 million, $4.8 million and $3.7 million will be amortized in 2013, 2014 and 2015, respectively.

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

In January 2013, in connection with the sale of the Company's Sacramento Basin natural gas properties, the Company settled all natural gas derivative contracts, as well as all natural gas basis swaps, and incurred a realized loss of $3.8 million. Also in January 2013, the Company settled 25%, or 975 barrels per day, of oil basis swaps, incurring a realized loss of $2.1 million. In April 2013, the Company settled the remaining 75%, or 2,925 barrels per day, of the oil basis swaps and incurred a realized loss of $3.6 million. The total amount paid to settle derivative contracts was $9.5 million in the first six months of 2013. During the second quarter of 2012, the Company unwound certain of its then existing oil and natural gas derivative contracts and received $11.0 million. When combined with the amounts received in the first quarter of 2012 of $41.2 million, the Company received a total of $52.2 million from the termination of derivative contracts during the first six months of 2012.

As of June 30, 2013, the Company had entered into certain swap, collar and put agreements related to its oil 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 differential between the agreement price and the price per the applicable index, Inter-Continental Exchange Brent ("Brent").

Prior to their settlement as discussed above, the Company had entered into certain oil basis swaps in order to fix the differential between the WTI crude price index and Brent. Historically, the two price

indexes had 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 Southern California indexes most relevant to the Company have in recent periods tracked more closely with Brent prices than with WTI.

Fair Value of Derivative Instruments. The estimated fair values of derivatives included in the condensed consolidated balance sheets at June 30, 2013 and December 31, 2012 are summarized below. The net fair value of the Company's derivatives changed by $37.8 million from a net liability of $40.7 million at December 31, 2012 to a net liability of $2.9 million at June 30, 2013, primarily due to (i) changes in the futures prices for oil, 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 2013. 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 cash-flow hedging instruments for accounting purposes. The main headings represent the balance sheet captions for the contracts presented.

	December 31, 2012			June 30, 2013

Current Assets—Commodity derivatives:
Oil derivative contracts	$	153		$	2,128
Other Assets—Commodity derivatives:
Oil derivative contracts		—			478
Current Liabilities—Commodity derivatives:
Oil derivative contracts		(19,817	)		(2,359	)
Gas derivative contracts		(790	)		—

		(20,607	)		(2,359	)

Commodity derivatives:
Oil derivative contracts		(17,482	)		(3,137	)
Gas derivative contracts		(2,805	)		—

		(20,287	)		(3,137	)

Net derivative asset (liability)	$	(40,741	)	$	(2,890	)

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 when incurred by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include

estimates of costs to be incurred, the Company's credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method.

The following table summarizes the activities for the Company's asset retirement obligations for the six months ended June 30, 2012 and 2013 (in thousands):

	Six Months Ended June 30,

	2012			2013
Asset retirement obligations at beginning of period	$	92,508		$	43,319
Revisions of estimated liabilities		(25	)		(332	)
Liabilities incurred or acquired		904			119
Liabilities settled or disposed		(3,160	)		(7,551	)
Accretion expense		2,841			1,271

Asset retirement obligations at end of period		93,068			36,826
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)		(500	)		(2,200	)

Long-term asset retirement obligations	$	92,568		$	34,626

Discount rates used to calculate the present value vary depending on the estimated timing of the obligation, but typically range between 4% and 9%. The liabilities settled or disposed of $7.6 million during the first six months of 2013 primarily relate to the Sacramento Basin asset sale.

On October 3, 2012, Timothy Marquez, Venoco's former CEO and currently its Executive Chairman, completed a transaction whereby he, through an affiliate, acquired all of the outstanding stock of the Company he did not beneficially own for $12.50 per share. As a result, Venoco's common stock is no longer publicly traded and the Company is wholly owned by DPC, 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 are pledged as security for debt of DPC, 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.

In connection with the going private transaction, all of the Company's equity based awards, which consisted of restricted share awards and stock option awards, were converted into cash settlement awards as follows:

After the going private transaction, the Company granted the following cash settlement or liability awards to officers, directors and certain employees of the Company:

The Company adopted an Employee Stock Ownership Plan ("ESOP") effective December 31, 2012 for eligible employees who are actively employed on the last day of the plan year. For each plan year, beginning in 2013, the Company will make discretionary contributions of restricted share units in DPC common stock to the ESOP based on a portion of the participant's eligible compensation, subject to certain Internal Revenue Code limitations. The number of ESOP restricted share units in DPC common stock granted to each participant is based on the total amount of the discretionary

contribution to the participant each year, divided by the fair market value of DPC common stock on the valuation date as determined by an independent appraiser. ESOP restricted share units generally vest over a four year period beginning with the participant's hire date or the date of the adoption of the ESOP, whichever is later. The value of participants' accounts is determined based on an appraisal, performed at least annually, of the fair market value of DPC common stock. Participants may begin making withdrawals from their accounts upon separation from the Company or upon reaching normal retirement age as determined by the Internal Revenue Code.

The following summarizes the Company's cash settlement awards granted during the six months ended June 30, 2013:

			Weighted Average Grant-Date Fair Value				Weighted Average Grant-Date Fair Value		Share Appreciation Rights			Weighted Average Grant-Date Fair Value				Weighted Average Grant-Date Fair Value

Outstanding, start of period	2,121,837		$	12.50	991,415		$	8.33		3,310,920		$	3.21	—		$	—
Granted	—		$	—	187,300		$	8.33		1,478,507		$	6.52	214,552		$	8.33
Vested or exercised	(774,693	)	$	12.50	(241,419	)	$	—		—		$	—	—		$	—
Cancelled and other	(81,845	)	$	12.50	(138,014	)	$	8.33		(374,744	)	$	3.51	(9,395	)	$	8.33

Outstanding, end of period	1,265,299				799,282					4,414,683				205,157

Exercisable, end of period										805,641
Aggregate intrinsic value of SARs exercisable									$	—

The grant date fair value of each SAR is estimated using the Black-Scholes valuation model. Valuation models require the input of highly subjective assumptions, including the expected volatility of the price of the underlying stock. The Company's units have characteristics significantly different from those of traded units, and because changes in the subjective input assumptions can materially affect the fair value estimate, it is management's opinion that the valuations afforded by existing models are different from the value that the units would realize if traded in the market.

The following assumptions were used during the second quarter of 2013 to compute the grant date fair value of SARs:


		June 30, 2013
Expected lives		1.0 - 7.0 years
Risk free interest rates		0.15% - 1.96%
Estimated volatilities		45% - 60%
Dividend yield		0.0%

The Company calculated the expected life of units granted using the "simplified method" set forth in Staff Accounting Bulletin 107 (average of vesting period and term of the option). For deep out-of-the-money SARs where the derived service period is materially longer than the explicit service period, the requisite service period is based on the derived service period. The risk free interest rate was based on the U.S. Treasury yield curve in effect at the time of grant. The expected volatility was

based on the historical volatility of public companies with characteristics similar to the Company for the past seven years.

The Company measures its liability awards based on the award's fair value remeasured at each reporting date until the date of settlement. Compensation cost for each period until settlement is based on the change (or a portion of the change, depending on the percentage of the requisite service that has been rendered at the reporting date). Changes in the fair value of a liability that occur after the end of the requisite service period are compensation cost of the period in which the changes occur. Any difference between the amount for which a liability award is settled and its fair value at the settlement date is an adjustment of compensation cost in the period of settlement.

The composition of the share-based compensation liability at June 30, 2013 is as follows (in thousands):

At the Company's request, certain officers and directors have agreed to delay receipt of payment until January 2014 for a portion of their RTR awards that were due to be paid in early 2013.

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

As of June 30, 2013, there was $31.3 million of total unrecognized compensation cost, which is expected to be recognized over a period of 3.5 years.

Fair value is defined as the price that would be received in the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the

asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. The FASB has established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).

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 of assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of June 30, 2013 (in thousands).

The Company's commodity derivative instruments consist primarily of swaps, collars and option contracts for oil. 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.

Share-based compensation. The Company's current share-based compensation liability includes a liability for restricted share unit awards (RSUs), share appreciation rights (SARs) and employee stock ownership plan unit awards (ESOP). The fair value of DPC common stock is a significant input for determining the share-based compensation amounts and the liability amounts for these cash settled awards. DPC is a privately held entity for which there is no available market price or principal market for DPC common shares. Inputs for determining the fair market value of this instrument are unobservable and are therefore classified as Level 3 inputs. The Company utilizes various valuation methods for determining the fair market value of this instrument including a net asset value approach, a comparable company approach, a discounted cash flow approach and a transaction approach. The Company's estimate of the value of DPC shares is highly dependent on commodity prices, cost assumptions, discount rates, oil and natural gas proved reserves, overall market conditions and the identification of companies and transactions that are comparable to the Company's operations and reserve characteristics. While some inputs to the Company's calculation of fair value of DPC shares are from published sources, others, such as reserve values, the discount rate and expected future cash flows, are derived from the Company's own calculations and estimates. Significant changes in the unobservable inputs, summarized above, could result in a significantly different fair value estimate.

The grant date fair value of each SAR is estimated using the Black-Scholes valuation model. The fair market value of DPC common shares is a significant input into the Black-Scholes valuation model. Valuation models require the input of highly subjective assumptions, including the expected volatility of the price of the underlying stock. DPC shares have characteristics significantly different from those of traded units, and because changes in the subjective input assumptions can materially affect the fair value estimate, it is management's opinion that the valuations afforded by existing models are different from the value that the shares would realize if traded in the market.

The following table summarizes the changes in fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy (in thousands):

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

In the ordinary course of our business we are named from time to time as a defendant in various legal proceedings. We maintain liability insurance and believe that our coverage is reasonable in view of the legal risks to which our business is subject.

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 (the "City") 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 their cancers and other maladies. In July 2012 the Company entered into a settlement agreement, for an immaterial amount, pursuant to which all pending cases against the defendants have been dismissed with prejudice.

The City and its insurance companies have made claims for indemnity against the Company and others related to costs incurred by the City in defending itself against the Beverly Hills Lawsuits, which the Company and the other defendants are disputing. The Company believes that these claims for indemnity are without merit. Based on information known to the Company, the Company does not believe that it is probable that the 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 (the "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 consider the cost of

transporting oil from the South Ellwood field to the point of sale in calculating the market price of oil at the wellhead for purposes of calculating its royalty obligation. 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 transportation costs, the Company believes that state law allows the Company to consider the cost of delivering the oil from the field to the point of sale in determining the market price of the oil at the wellhead. 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 adjust its sales price to include all transportation costs associated with marketing its crude oil.

The Company is in discussions with the SLC to settle the matter. The proposed settlement would (i) affirm that the Company's methodology for computing royalties on production from the South Ellwood field based on actual sales prices is correct and (ii) settle all claims by the SLC for royalty under payments and claims by the Company for royalty over payments through February 2013. Under the proposed settlement neither party would pay the other party. A settlement agreement has not been signed. It is possible that the final terms could vary or that a final settlement is not reached.

Delaware Litigation—In August 2011 Timothy Marquez, the then-Chairman and CEO 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 did 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. On January 16, 2012, the Company entered into a Merger Agreement with Mr. Marquez and certain of his affiliates pursuant to which the Company, Mr. Marquez and his affiliates would effect the going private transaction. 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. In March 2013 the plaintiffs in Delaware filed a consolidated amended class action complaint in which they requested that the court determine among other things that (i) the merger consideration is inadequate and the Merger Agreement was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable and (ii) the merger should be rescinded or in the alternative, the class should be awarded damages to compensate them for the loss as a result of the breach of fiduciary duties by the defendants. The Colorado actions have been administratively closed pending resolution of the Delaware case. The Company has reviewed the allegations contained in the amended complaint and believes they are without merit. Trial in this matter is expected to occur in late 2014.

Denbury Arbitration—In January 2013 the Company and its wholly owned subsidiary, TexCal Energy South Texas, L.P. ("TexCal"), notified Denbury Resources, Inc. ("Denbury") through its subsidiary Denbury Onshore, LLC that it was invoking the arbitration provisions contained in contracts between TexCal and Denbury pursuant to which TexCal conveyed its interest in the Hastings Complex to Denbury and retained a reversionary interest. Denbury is obligated to convey the reversionary interest

to TexCal at "payout," as defined in the contracts. The dispute involves the calculation of the cost of CO₂ delivered to the Hastings Complex which is used in Denbury's enhanced oil recovery operations. The Company believes that Denbury has materially overcharged the payout account for the cost of CO₂ and the cost of transporting it to the Hastings Complex. The arbitration is expected to be completed in late 2013. An adverse determination in the arbitration proceeding could reduce the amount of proved reserves from this reversionary interest and delay the timing for cash flows from those reserves.

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, of these other claims and legal actions will not have a material effect on its consolidated financial position, results of operations or liquidity.

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 June 30, 2013. 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.

CONDENSED CONSOLIDATING BALANCE SHEETS
AT DECEMBER 31, 2012 (Unaudited)
(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	53,818		$	—		$	—		$	—		$	53,818
Accounts receivable		109,308			99			(1,051	)		—			108,356
Inventories		5,101			—			—			—			5,101
Other current assets		4,448			—			—			—			4,448
Commodity derivatives		153			—			—			—			153

TOTAL CURRENT ASSETS		172,828			99			(1,051	)		—			171,876

PROPERTY, PLANT & EQUIPMENT, NET		812,723			(184,155	)		20,034			—			648,602
INVESTMENTS IN AFFILIATES		541,141			—			—			(541,141	)		—
OTHER		25,543			60			—			—			25,603

TOTAL ASSETS	$	1,552,235		$	(183,996	)	$	18,983		$	(541,141	)	$	846,081

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	57,315		$	—		$	—		$	—		$	57,315
Interest payable		27,862			—			—			—			27,862
Current portion of long-term debt		104,494			—			—			—			104,494
Commodity derivatives		20,607			—			—			—			20,607
Share-based compensation		10,424			—			—			—			10,424

TOTAL CURRENT LIABILITIES:		220,702			—			—			—			220,702

LONG-TERM DEBT		849,190			—			—			—			849,190
COMMODITY DERIVATIVES		20,287			—			—			—			20,287
ASSET RETIREMENT OBLIGATIONS		39,003			1,407			709			—			41,119
SHARE-BASED COMPENSATION		10,441			—			—			—			10,441
INTERCOMPANY PAYABLES (RECEIVABLES)		708,270			(653,163	)		(55,107	)		—			—

TOTAL LIABILITIES		1,847,893			(651,756	)		(54,398	)		—			1,141,739

TOTAL STOCKHOLDERS' EQUITY		(295,658	)		467,760			73,381			(541,141	)		(295,658	)

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,552,235		$	(183,996	)	$	18,983		$	(541,141	)	$	846,081

CONDENSED CONSOLIDATING BALANCE SHEETS
AT JUNE 30, 2013 (Unaudited)
(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,516		$	—		$	—		$	—		$	3,516
Accounts receivable		27,982			95			(1,383	)		—			26,694
Inventories		5,344			—			—			—			5,344
Other current assets		2,833			—			—			—			2,833
Commodity derivatives		2,128			—			—			—			2,128

TOTAL CURRENT ASSETS		41,803			95			(1,383	)		—			40,515

PROPERTY, PLANT & EQUIPMENT, NET		798,251			(184,203	)		19,664			—			633,712
COMMODITY DERIVATIVES		478			—			—			—			478
INVESTMENTS IN AFFILIATES		548,746			—			—			(548,746	)		—
OTHER		20,439			60			—			—			20,499

TOTAL ASSETS	$	1,409,717		$	(184,048	)	$	18,281		$	(548,746	)	$	695,204

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	40,677		$	—		$	—		$	—		$	40,677
Interest payable		21,326			—			—			—			21,326
Commodity derivatives		2,359			—			—			—			2,359
Share-based compensation		15,305			—			—			—			15,305

TOTAL CURRENT LIABILITIES:		79,667			—			—			—			79,667

LONG-TERM DEBT		828,145			—			—			—			828,145
COMMODITY DERIVATIVES		3,137			—			—			—			3,137
ASSET RETIREMENT OBLIGATIONS		32,432			1,465			729			—			34,626
SHARE-BASED COMPENSATION		8,298			—			—			—			8,298
INTERCOMPANY PAYABLES (RECEIVABLES)		716,707			(653,715	)		(62,992	)		—			—

TOTAL LIABILITIES		1,668,386			(652,250	)		(62,263	)		—			953,873

TOTAL STOCKHOLDERS' EQUITY		(258,669	)		468,202			80,544			(548,746	)		(258,669	)

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,409,717		$	(184,048	)	$	18,281		$	(548,746	)	$	695,204

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

	Venoco, Inc.			Guarantor Subsidiaries		Non-Guarantor Subsidiary			Eliminations			Consolidated

REVENUES:
Oil and natural gas sales	$	80,585		$	351	$	—		$	—		$	80,936
Other		1,192			5		2,773			(2,407	)		1,563

Total revenues		81,777			356		2,773			(2,407	)		82,499
EXPENSES:
Lease operating expenses		19,614			7		472			—			20,093
Property and production taxes		5,269			1		32			—			5,302
Transportation expense		2,576			—		—			(2,319	)		257
Depletion, depreciation and amortization		20,983			26		204			—			21,213
Accretion of asset retirement obligations		1,410			30		10			—			1,450
General and administrative, net of amounts capitalized		9,835			1		121			(88	)		9,869

Total expenses		59,687			65		839			(2,407	)		58,184

Income (loss) from operations		22,090			291		1,934			—			24,315
FINANCING COSTS AND OTHER:
Interest expense, net		16,813			—		(933	)		—			15,880
Amortization of deferred loan costs		585			—		—			—			585
Commodity derivative losses (gains), net		(6,696	)		—		—			—			(6,696	)

Total financing costs and other		10,702			—		(933	)		—			9,769

Equity in subsidiary income		1,958			—		—			(1,958	)		—

Income (loss) before income taxes		13,346			291		2,867			(1,958	)		14,546
Income tax provision (benefit)		(1,200	)		111		1,089			—			—

Net income (loss)	$	14,546		$	180	$	1,778		$	(1,958	)	$	14,546

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
THREE MONTHS ENDED JUNE 30, 2013 (Unaudited)
(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries		Non-Guarantor Subsidiary			Eliminations			Consolidated

REVENUES:
Oil and natural gas sales	$	81,158		$	291	$	—		$	—		$	81,449
Other		315			—		3,497			(2,902	)		910

Total revenues		81,473			291		3,497			(2,902	)		82,359

EXPENSES:
Lease operating expense		17,369			15		530			—			17,914
Property and production taxes		1,364			15		28			—			1,407
Transportation expense		2,852			3		—			(2,810	)		45
Depletion, depreciation and amortization		12,168			26		212			—			12,406
Accretion of asset retirement obligations		575			30		10			—			615
General and administrative, net of amounts capitalized		10,333			1		133			(92	)		10,375

Total expenses		44,661			90		913			(2,902	)		42,762

Income from operations		36,812			201		2,584			—			39,597

FINANCING COSTS AND OTHER:
Interest expense, net		18,567			—		(1,166	)		—			17,401
Amortization of deferred loan costs		906			—		—			—			906
Commodity derivative losses (gains), net		(19,951	)		—		—			—			(19,951	)

Total financing costs and other		(478	)		—		(1,166	)		—			(1,644	)

Equity in subsidiary income		2,448			—		—			(2,448	)		—

Income (loss) before income taxes		39,738			201		3,750			(2,448	)		41,241
Income tax provision (benefit)		(1,503	)		78		1,425			—			—

Net income (loss)	$	41,241		$	123	$	2,325		$	(2,448	)	$	41,241

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 2012 (Unaudited)
(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries		Non-Guarantor Subsidiary			Eliminations			Consolidated

REVENUES:
Oil and natural gas sales	$	163,600		$	724	$	—		$	—		$	164,324
Other		2,677			18		5,001			(4,158	)		3,538

Total revenues		166,277			742		5,001			(4,158	)		167,862
EXPENSES:
Lease operating expense		43,671			27		845			—			44,543
Property and production taxes		6,884			1		32			—			6,917
Transportation expense		8,652			—		—			(3,983	)		4,669
Depletion, depreciation and amortization		43,066			52		349			—			43,467
Accretion of asset retirement obligations		2,758			64		19			—			2,841
General and administrative, net of amounts capitalized		22,158			1		246			(175	)		22,230

Total expenses		127,189			145		1,491			(4,158	)		124,667

Income (loss) from operations		39,088			597		3,510			—			43,195
FINANCING COSTS AND OTHER:
Interest expense, net		33,477			—		(1,886	)		—			31,591
Amortization of deferred loan costs		1,154			—		—			—			1,154
Commodity derivative losses (gains), net		23,842			—		—			—			23,842

Total financing costs and other		58,473			—		(1,886	)		—			56,587

Equity in subsidiary income		3,716			—		—			(3,716	)		—

Income (loss) before income taxes		(15,669	)		597		5,396			(3,716	)		(13,392	)
Income tax provision (benefit)		(2,277	)		227		2,050			—			—

Net income (loss)	$	(13,392	)	$	370	$	3,346		$	(3,716	)	$	(13,392	)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 2013 (Unaudited)
(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries		Non-Guarantor Subsidiary			Eliminations			Consolidated

REVENUES:
Oil and natural gas sales	$	166,807		$	601	$	—		$	—		$	167,408
Other		1,024			—		6,768			(5,578	)		2,214

Total revenues		167,831			601		6,768			(5,578	)		169,622

EXPENSES:
Lease operating expense		35,256			27		1,162			—			36,445
Property and production taxes		2,491			15		28			—			2,534
Transportation expense		5,470			6		—			(5,393	)		83
Depletion, depreciation and amortization		23,507			52		419			—			23,978
Accretion of asset retirement obligations		1,193			58		20			—			1,271
General and administrative, net of amounts capitalized		25,264			1		270			(185	)		25,350

Total expenses		93,181			159		1,899			(5,578	)		89,661

Income from operations		74,650			442		4,869			—			79,961

FINANCING COSTS AND OTHER:
Interest expense, net		38,549			—		(2,294	)		—			36,255
Amortization of deferred loan costs		2,019			—		—			—			2,019
Loss on extinguishment of debt		21,297			—		—			—			21,297
Commodity derivative losses (gains), net		(16,608	)		—		—			—			(16,608	)

Total financing costs and other		45,257			—		(2,294	)		—			42,963

Equity in subsidiary income		4,715			—		—			(4,715	)		—

Income (loss) before income taxes		34,108			442		7,163			(4,715	)		36,998
Income tax provision (benefit)		(2,890	)		168		2,722			—			—

Net income (loss)	$	36,998		$	274	$	4,441		$	(4,715	)	$	36,998

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
SIX MONTHS ENDED JUNE 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	$	94,096		$	740		$	5,095		$	—	$	99,931
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties		(126,136	)		(39	)		(5,864	)		—		(132,039	)
Acquisitions of oil and natural gas properties		(235	)		—			—			—		(235	)
Expenditures for property and equipment and other		(1,211	)		—			—			—		(1,211	)
Proceeds from sale of oil and natural gas properties		23,368			—			—			—		23,368

Net cash provided by (used in) investing activities		(104,214	)		(39	)		(5,864	)		—		(110,117	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from (repayments of) intercompany borrowings		(68	)		(701	)		769			—		—
Proceeds from long-term debt		140,000			—			—			—		140,000
Principal payments on long-term debt		(138,000	)		—			—			—		(138,000	)
Payments for deferred loan costs		(93	)		—			—			—		(93	)
Proceeds from stock incentive plans and other		133			—			—			—		133

Net cash provided by (used in) financing activities		1,972			(701	)		769			—		2,040

Net increase (decrease) in cash and cash equivalents		(8,146	)		—			—			—		(8,146	)
Cash and cash equivalents, beginning of period		8,165			—			—			—		8,165

Cash and cash equivalents, end of period	$	19		$	—		$	—		$	—	$	19

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30, 2013 (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	$	29,529		$	593		$	9,373		$	—	$	39,495
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties		(45,563	)		5			42			—		(45,516	)
Acquisitions of oil and natural gas properties		(40	)		—			—			—		(40	)
Expenditures for property and equipment and other		(2,007	)		—			—			—		(2,007	)
Proceeds from sale of oil and natural gas properties		100,332			—			—			—		100,332

Net cash provided by (used in) investing activities		52,722			5			42			—		52,769
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from (repayments of) intercompany borrowings		10,013			(598	)		(9,415	)		—		—
Proceeds from long-term debt		294,900			—			—			—		294,900
Principal payments on long-term debt		(426,900	)		—			—			—		(426,900	)
Premium paid to paydown debt		(1,107	)		—			—			—		(1,107	)
Payments for deferred loan costs		(9,450	)		—			—			—		(9,450	)
Going private share repurchase costs		(9	)		—			—			—		(9	)

Net cash provided by (used in) financing activities		(132,553	)		(598	)		(9,415	)		—		(142,566	)

Net increase (decrease) in cash and cash equivalents		(50,302	)		—			—			—		(50,302	)
Cash and cash equivalents, beginning of period		53,818			—			—			—		53,818

Cash and cash equivalents, end of period	$	3,516		$	—		$	—		$	—	$	3,516

ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operation

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, 2012 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.

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

Going Private Transaction. In January 2012, we entered into a merger agreement with Timothy Marquez and certain of his affiliates pursuant to which an affiliate of Mr. Marquez agreed to acquire all of our common stock not beneficially owned by Mr. Marquez for $12.50 per share in cash. We refer to this transaction as the going private transaction. The going private transaction closed in October 2012. Following the closing, Venoco's common stock is no longer publicly traded; however, we will continue reporting 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 "—Liquidity and Capital Resources—Capital Resources and Requirements." We subsequently entered into an amendment to the revolving credit agreement and repaid all amounts outstanding under the second lien term loan as discussed below.

Sacramento Basin Asset Sale. In December 2012, we completed the sale of certain properties in the Sacramento Basin and San Joaquin Valley areas of California to an unrelated third party for $250 million, subject to certain closing adjustments, of which $100.6 million was placed into escrow pending the receipt of consents to assign and the expiration or waiver of preferential purchase rights relating to certain of the properties. Of the $100.6 million placed into escrow, $72.8 million was received two days after closing and $17.9 million was received in the first quarter of 2013. The remaining $9.9 million was released as of June 30, 2013. We applied proceeds from the sale to pay down $214.7 million of the principal balance outstanding on the second lien term loan facility and a $6.4 million prepayment penalty. The assets sold had proved reserves of approximately 44,900 MBOE as of December 31, 2011. Production from those assets averaged 8,939 BOE/d in 2012, 100% of which was natural gas.

Amended and Restated Revolving Credit Agreement and Second Lien Repayment. In March 2013, we entered into an amendment to the revolving credit agreement that increased the borrowing base under the facility to $270 million. We then borrowed an additional $107 million under the facility and used those funds to repay the remaining amounts outstanding under the second lien term loan ($100 million) and a prepayment penalty of $3.0 million. The amendment also changed certain financial covenants included in the revolving credit agreement, as described in "—Liquidity and Capital Resources—Capital Resources and Requirements."

In the first six months of 2013 our development, exploitation and exploration capital expenditures were $43 million, with approximately $39 million incurred for Southern California legacy projects and $4 million for onshore Monterey projects. We reduced our overall capital expenditures, and increased our focus on development relative to exploration drilling, following the completion of the going private transaction. Our 2013 development, exploitation and exploration capital expenditure budget is $91 million, of which approximately $78 million is expected to be devoted to our legacy Southern California assets and approximately $13 million to onshore Monterey shale activities. The expected reduction in capital expenditures in 2013 is a result of our focus on deleveraging following the completion of the going private transaction.

The aggregate levels of capital expenditures for the remainder of 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 2013 capital spending program.

In the first quarter of 2013, we successfully completed the 3242-4 RD well to an in-fill location at the South Ellwood field. In 2013, we have also drilled two additional wells in the field, the 3242-15 well and the 3242-19 well. The 3242-15 well, which was drilled to an in-fill location near the 3242-4RD well and our 3242-12 well, was recently completed and is in the dewatering phase, but has produced at a maximum 24 hour rate of over 1,000 BOE/d. In June 2013, the 3242-4RD well produced at an average gross rate of approximately 900 BOE/d, and the 3242-12 well produced at an average gross rate of approximately 2,500 BOE/d. The 3242-19 well, which was drilled to a probable location in a different part of the field, is in the process of being completed and we expect to initiate testing the well beginning in mid-August. During the remainder of 2013, we plan to replace the existing de-rated power cable to Platform Holly. The new power cable will provide us with the ability to place up to three additional gross wells on electric submersible pumps (in lieu of gas lift), which is expected to improve our recovery capabilities.

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.

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. We spud one well at the West Montalvo field during the second quarter and we expect to complete this well in the third quarter. For the remainder of 2013, we plan to spud three additional wells in the field. The field has not been fully delineated offshore or fully developed onshore.

In the Sockeye field, there are no significant development projects planned for 2013.

In 2006, we began actively leasing onshore acreage in Southern California targeting the Monterey shale. Our leasing 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. Our onshore

Monterey shale acreage position currently totals approximately 61,000 gross and 46,000 net acres and is located primarily in three basins: Santa Maria, Salinas Valley and San Joaquin.

Since 2010, we have pursued an active drilling program targeting the onshore Monterey shale formation. From that time through June 30, 2013, we have spud 29 wells and have set casing on 26 of those wells. To date, we have not seen material levels of production or reserves from the program and have, following the completion of the going private transaction, reduced our capital expenditures related to the project. Based on the data we have gathered and the results we have seen to date at the Sevier field, however, we believe that our testing efforts and delineation drilling in the area will ultimately result in commercial levels of production from the field. The 2013 capital expenditure budget contemplates drilling one horizontal well in the Sevier field and continued improvements to our existing production facilities in the field.

Sale of Sacramento Basin and San Joaquin Valley Assets. On December 31, 2012, we sold all of our producing acreage in the Sacramento Basin and San Joaquin Valley areas (not including any acreage in the Sevier field) to an unrelated third party for $250 million. See "—Recent Events—Sacramento Basin Asset Sale."

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 dispositions of oil and natural gas properties, primarily in and around our existing core areas 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, 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 assets included in the Sacramento Basin asset sale included substantially all of our properties that produce predominately natural gas. We therefore expect to have limited exposure to changes in natural gas prices for the foreseeable future.

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 August 1, 2013, we had hedge contract floors covering 6,700 barrels of oil per day for 2013. We settled all of our natural gas contracts in January 2013 as a result of the Sacramento Basin asset sale. We have also secured hedge contracts for portions of our 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 several new sales contracts in early 2012 and early 2013 based on certain Southern California crude price indexes, which traded at a premium to WTI throughout 2011 and 2012 and have more closely tracked with the Inter Continental Exchange Brent crude price index ("Brent").

Expected Production. Our 2013 capital spending has been allocated approximately 86% to our legacy Southern California fields and 14% 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, the planned increase for 2013 and the success of two of our recently drilled South Ellwood wells, we expect production from those assets to increase in 2013. Overall, we expect production to be significantly lower in 2013 than it was in 2012 due primarily to the Sacramento Basin asset sale. On a pro forma basis, excluding production from properties included in the asset sale, we expect production to increase in 2013 compared to 2012.

Lease Operating Expenses. Lease operating expenses ("LOE") of $19.67 per BOE for the first six months of 2013 were higher than our full year 2012 results of $14.48 per BOE. We expect that the continuing shift in our focus to oil development will result in an increase in our LOE per BOE in 2013 relative to 2012.

Property and Production Taxes. Property and production taxes of $1.37 per BOE for the first six months of 2013 were slightly lower than our full year 2012 results of $1.53 per BOE. We expect our 2013 property and production taxes to be higher on a per BOE basis than they were in 2012. Our ad valorem tax expense is highly sensitive to drilling results and the estimated present value of future net cash flows from new wells, and may be volatile in the future.

Transportation Expenses. Transportation expenses were $0.04 per BOE for the first six months of 2013 compared to $0.81 per BOE for the full year 2012. The decrease was due to the elimination, in mid-May 2012, of the South Ellwood barge operation as a result of the completion of the onshore pipeline during the first quarter of 2012. We expect that our transportation expenses will decrease in 2013 compared to 2012 as a result of the use of the onshore pipeline for the full year.

General and Administrative Expenses. General and administrative expenses were $11.78 per BOE (excluding non-cash share-based compensation charges of $1.90 per BOE) for the first six months of 2013 compared to $6.13 per BOE for the full year 2012 (excluding non-cash share-based compensation charges of $1.58 per BOE and costs of $1.76 per BOE related to the going private transaction and one-time Sacramento Basin exit and disposal costs). Excluding share-based compensation charges and going private-related charges we expect our 2013 G&A costs to be slightly less than 2012, and, on a per BOE basis, to increase in 2013 compared to 2012 due to our lower expected production in 2013. In connection with the going private transaction, our equity based awards were converted into cash settlement (or liability) awards. We measure liability awards based on the award's fair value remeasured at each reporting date until the date of settlement. Compensation costs for each period until settlement is based on the change (or a portion of the change, depending on the percentage of the requisite service that has been rendered at the reporting date). As a result of these changes, our share-based compensation expense will likely be higher in 2013 and will likely fluctuate more than when these awards were equity based.

Depreciation, Depletion and Amortization (DD&A). DD&A for the first six months of 2013 was $12.94 per BOE compared to $13.68 per BOE for the full year 2012. We expect our 2013 DD&A to decrease on a per BOE basis compared to our 2012 results.

Unrealized Derivative Gains and Losses. Unrealized derivative 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, 2009 and 2012 as well as taxable losses in each of the tax years from 2007 through 2012. 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, 2012 and June 30, 2013 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 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.

Our expectations with respect to future production rates, expenses and the other matters discussed above are subject to a number of uncertainties, including those discussed and referenced in "Risk Factors." For example, with respect to future production rates, uncertainties include those associated with third party services, limitations on capital expenditures resulting from the terms of our debt agreements, the availability of drilling rigs, oil prices, events resulting in unexpected downtime, permitting issues and 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.

The following table reflects the components of our oil and natural gas production and sales prices, and our operating revenues, costs and expenses, for the periods indicated. No pro forma adjustments have been made for the acquisitions and divestitures of oil and natural gas properties, which will affect

the comparability of the data below. The information set forth below is not necessarily indicative of future results.

	Three Months Ended June 30,						Six Months Ended June 30,

	2012			2013			2012			2013
Production Volume(1):
Oil (MBbls)		692			852			1,333			1,663
Natural gas (MMcf)		5,174			267			10,842			1,140
MBOE(2)		1,554			897			3,140			1,853
Daily Average Production Volume:
Oil (Bbls/d)		7,604			9,363			7,324			9,188
Natural gas (Mcf/d)		56,857			2,934			59,571			6,298
BOE/d(2)		17,080			9,852			17,253			10,238
Oil Price per Bbl Produced (in dollars):
Realized price	$	100.38		$	93.46		$	99.55		$	96.51
Realized commodity derivative gain (loss)		(9.56	)		(1.78	)		(7.73	)		(6.17	)

Net realized price	$	90.82		$	91.68		$	91.82		$	90.34

Natural Gas Price per Mcf (in dollars):
Realized price	$	2.38		$	4.58		$	2.58		$	3.91
Realized commodity derivative gain (loss)		0.47			—			0.55			—

Net realized price	$	2.85		$	4.58		$	3.13		$	3.91

Expense per BOE:
Lease operating expenses	$	12.93		$	19.97		$	14.19		$	19.67
Property and production taxes		3.41			1.57			2.20			1.37
Transportation expenses		0.17			0.05			1.49			0.04
Depreciation, depletion and amortization		13.65			13.83			13.84			12.94
General and administrative expense, net(3)		6.35			11.57			7.08			13.68
Interest expense		10.22			19.40			10.06			19.57

Oil and Natural Gas Sales. Oil and natural gas sales increased $0.5 million (1%) to $81.4 million in the second quarter of 2013 compared to $80.9 million in the second quarter of 2012. The increase was due to higher oil production, partially offset by lower natural gas production, as described below.

Oil sales increased by $11.6 million (17%) in the second quarter of 2013 to $80.2 million compared to $68.6 million in the second quarter of 2012. Oil production increased by 23%, with production of 852 MBbls in the second quarter of 2013 compared to 692 MBbls in the second quarter of 2012. The increase is primarily due to higher production at our South Ellwood field, resulting from successful

drilling activity. Our average realized price for oil decreased $6.92 per Bbl (7%) from $100.38 per Bbl in the second quarter of 2012 to $93.46 per Bbl for the second quarter of 2013.

Natural gas sales decreased $11.1 million (90%) in the second quarter of 2013 to $1.2 million compared to $12.3 million in the second quarter of 2012. Natural gas production decreased by 95% in the second quarter of 2013, with production of 267 MMcf compared to 5,174 MMcf in the second quarter of 2012. The decrease is primarily due to the sale of Sacramento Basin assets. Our average realized price for natural gas increased $2.20 per Mcf (92%) from $2.38 per Mcf in the second quarter of 2012 to $4.58 per Mcf in the second quarter of 2013.

Other Revenues. Other revenues decreased $0.7 million (42%) in the second quarter of 2013 to $0.9 million compared to $1.6 million in the second quarter of 2012. During the second quarter of 2012, we received revenues related to sub-charter activity of the 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 second quarter of 2013.

Lease Operating Expenses. Lease operating expenses ("LOE") decreased $2.2 million (11%) in the second quarter of 2013 to $17.9 million compared to $20.1 million in the second quarter of 2012. The decrease was primarily due to the sale of Sacramento Basin assets. Excluding the Sacramento Basin assets included in the sale, LOE increased $1.5 million (9%) in the second quarter of 2013 to $17.9 million compared to $16.4 million in the second quarter of 2012. In the second quarter of 2013 we incurred higher non-recurring repairs at our West Montalvo field than in the second quarter of 2012. On a per unit basis, LOE increased by $7.04 per BOE from $12.93 in the second quarter of 2012 to $19.97 in the second quarter of 2013. Excluding the Sacramento Basin assets sold, on a per unit basis, LOE decreased by $2.75 per BOE from $22.73 in the second quarter of 2012 to $19.98 in the second quarter of 2013.

Property and Production Taxes. Property and production taxes decreased $3.9 million (73%) in the second quarter of 2013 to $1.4 million compared to $5.3 million in the second quarter of 2012. The decrease is primarily the result of higher supplemental taxes in the 2012 period in connection with additional reserves from new wells. On a per BOE basis, property and production taxes decreased $1.84 per BOE to $1.57 in the second quarter of 2013 from $3.41 in the second quarter of 2012.

Transportation Expenses. Transportation expenses decreased $0.2 million (82%) to $45,000 in the second quarter of 2013 compared to $0.3 million in the second quarter of 2012. The decrease was due to elimination, in mid-May 2012, of the South Ellwood barge operation as a result of the completion of the onshore pipeline during the second quarter of 2012.

Depletion, Depreciation and Amortization (DD&A). DD&A expense decreased $8.8 million (42%) to $12.4 million in the second quarter of 2013 compared to $21.2 million in the second quarter of 2012. The decrease was primarily due to the sale of the Sacramento Basin assets. Excluding the Sacramento Basin assets sold, DD&A increased $3.8 million (44%) to $12.4 million in the second quarter of 2013 compared to $8.6 million in the second quarter of 2012. This increase is primarily due to higher production at our South Ellwood and West Montalvo fields, resulting from successful drilling activity. DD&A expense on a per unit basis increased $0.18 per BOE to $13.83 per BOE for the second quarter of 2013 compared to $13.65 per BOE for the second quarter of 2012.

Accretion of Abandonment Liability. Accretion expense decreased $0.9 million (58%) to $0.6 million in the second quarter of 2013 compared to $1.5 million in the second quarter of 2012. The decrease is primarily the result of the Sacramento Basin asset sale.

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

G&A expenses increased $0.5 million (5%) to $10.4 million in the second quarter of 2013 compared to $9.9 million in the second quarter of 2012. The increase is primarily due to higher share-based compensation expense of $3.8 million (net of amount capitalized) charged to G&A in the second quarter of 2013 compared to $1.0 million (net of amount capitalized) in the second quarter of 2012, partially offset by lower employee related G&A in the second quarter of 2013 due to the Sacramento Basin asset sale. In connection with the going private transaction, our equity based awards were converted into cash settlement (or liability) awards. As a result of these changes, we expect that our share-based compensation expense will likely be higher in 2013 and will likely fluctuate more than when these awards were equity based. Excluding the effect of the non-cash share-based compensation expense and going private related costs, G&A expense increased to $10.32 per BOE in the second quarter of 2013 from $5.15 per BOE in the second quarter of 2012.

Interest Expense, Net. Interest expense, net of interest income, increased $1.5 million (10%) to $17.4 million in the second quarter of 2013 compared to $15.9 million in the second quarter of 2012. The increase was primarily the result of increased borrowings on the revolving credit facility in the second quarter of 2013.

Amortization of Deferred Loan Costs. Amortization of deferred loan costs increased $0.3 million (55%) to $0.9 million in the second quarter of 2013 compared to $0.6 million in the second quarter of 2012. The costs incurred relate to our loan agreements and are amortized over the estimated lives of the agreements.

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

realizing total losses of $3.6 million. Unrealized commodity derivative (gains) losses represent the change in the fair value of our open derivative contracts from period to period. Derivative premiums are amortized over the term of the underlying derivative contracts.

Income Tax Expense (Benefit). Due to our valuation allowance, there was no income tax expense (benefit) recorded for the quarters ended June 30, 2013 or 2012. 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 or for state income taxes.

Net Income (Loss). Net income for the second quarter of 2013 was $41.2 million compared to net income of $14.5 million for the same period in 2012. The change between periods is the result of the items discussed above.

Comparison of Six Months Ended June 30, 2013 to Six Months Ended June 30, 2012

Oil and Natural Gas Sales. Oil and natural gas sales increased $3.1 million (2%) to $167.4 million in the first half of 2013 compared to $164.3 million in the first half of 2012. The increase was due to higher oil production, partially offset by lower natural gas production, as described below.

Oil sales increased by $26.6 million (20%) in the first half of 2013 to $162.9 million compared to $136.3 million in the first half of 2012. Oil production increased by 25%, with production of 1,663 MBbls in the first half of 2013 compared to 1,333 MBbls in the first half of 2012. The increase is primarily due to higher production at our South Ellwood field, resulting from successful drilling activity. Our average realized price for oil decreased $3.04 per Bbl (3%) from $99.55 per Bbl in the first half of 2012 to $96.51 per Bbl for the first half of 2013.

Natural gas sales decreased $23.5 million (84%) in the first half of 2013 to $4.5 million compared to $28.0 million in the first half of 2012. Natural gas production decreased by 89% in the first half of 2013, with production of 1,140 MMcf compared to 10,842 MMcf in the first half of 2012. The decrease is primarily due to the sale of Sacramento Basin assets. Our average realized price for natural gas increased $1.33 per Mcf (52%) from $2.58 per Mcf in the first half of 2012 to $3.91 per Mcf in the first half of 2013.

Other Revenues. Other revenues decreased $1.3 million (37%) in the first half of 2013 to $2.2 million compared to $3.5 million in the first half of 2012. During the first half of 2012, we received revenues related to sub-charter activity of the 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 first half of 2013.

Lease Operating Expenses. Lease operating expenses ("LOE") decreased $8.1 million (18%) in the first half of 2013 to $36.4 million compared to $44.5 million in the first half of 2012. The decrease was primarily due to the sale of Sacramento Basin assets. Excluding the Sacramento Basin assets included in the sale, LOE decreased $1.0 million (3%) in the first half of 2013 to $35.9 million compared to $36.9 million in the first half of 2012, due primarily to non-recurring repair costs incurred at our South Ellwood field in the first half of 2012. On a per unit basis, LOE increased by $5.48 per BOE from $14.19 in the first half of 2012 to $19.67 in the first half of 2013. Excluding Sacramento Basin assets sold, on a per unit basis, LOE decreased by $0.96 per BOE from $26.31 in the first half of 2012 to $20.50 in the first half of 2013.

Property and Production Taxes. Property and production taxes decreased $4.4 million (63%) in the first half of 2013 to $2.5 million compared to $6.9 million in the first half of 2012. The decrease is primarily the result of higher supplemental taxes in the 2012 period in connection with additional

reserves from new wells. On a per BOE basis, property and production taxes decreased $0.83 per BOE to $1.37 in the first half of 2013 from $2.20 in the first half of 2012.

Transportation Expenses. Transportation expenses decreased $4.6 million (98%) to $83,000 in the first half of 2013 compared to $4.7 million in the first half of 2012. The decrease was due to elimination, in mid-May 2012, of the South Ellwood barge operation as a result of the completion of the onshore pipeline during the first half of 2012.

Depletion, Depreciation and Amortization (DD&A). DD&A expense decreased $19.5 million (45%) to $24.0 million in the first half of 2013 compared to $43.5 million in the first half of 2012. The decrease was primarily due to the sale of the Sacramento Basin assets. Excluding the Sacramento Basin assets sold, DD&A increased $5.5 million (30%) to $24.0 million in the first half of 2013 compared to $18.5 million in the first half of 2012. This increase is primarily due to higher production at our South Ellwood field, resulting from successful drilling activity. DD&A expense on a per unit basis decreased $0.90 per BOE to $12.94 per BOE for the first half of 2013 compared to $13.84 per BOE for the first half of 2012.

Accretion of Abandonment Liability. Accretion expense decreased $1.5 million (55%) to $1.3 million in the first half of 2013 compared to $2.8 million in the first half of 2012. The decrease is primarily the result of the Sacramento Basin asset sale.

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

G&A expenses increased $3.2 million (14%) to $25.4 million in the first half of 2013 compared to $22.2 million in the first half of 2012. The increase is primarily due to higher share-based compensation expense of $9.6 million (net of amount capitalized) charged to G&A in the first half of 2013 compared to $2.2 million (net of amount capitalized) in the first half of 2012, partially offset by lower employee related G&A in the first half of 2013 due to the Sacramento Basin asset sale. In connection with the going private transaction, our equity based awards were converted into cash settlement (or liability) awards. As a result of these changes, we expect that our share-based compensation expense will likely be higher in 2013 and will likely fluctuate more than when these awards were equity based. Excluding the effect of the non-cash share-based compensation expense and going private related costs, G&A expense increased to $11.78 per BOE in the first half of 2013 from $5.26 per BOE in the first half of 2012.

Interest Expense, Net. Interest expense, net of interest income, increased $4.6 million (15%) to $36.2 million in the first half of 2013 compared to $31.6 million in the first half of 2012. The increase was primarily the result of the issuance of the $315 million second lien term loan in connection with the going private transaction.

Amortization of Deferred Loan Costs. Amortization of deferred loan costs increased $0.8 million (75%) to $2.0 million in the first half of 2013 compared to $1.2 million in the first half of 2012. The costs incurred relate to our loan agreements and are amortized over the estimated lives of the agreements.

Loss on Extinguishment of Debt. The loss on extinguishment of debt of $21.3 million in the first half of 2013 resulted from a write-off of unamortized deferred loan costs, unamortized original issue discount and a premium paid for early repayment of our second lien term loan.

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 first half of 2013 reflect the settlement of contracts at prices above the relevant strike prices. In addition, in the first half of 2013, we unwound all outstanding natural gas derivative contracts for $3.8 million as a result of the Sacramento Basin asset sale, and unwound all of our oil basis swaps for $5.7 million, realizing total losses of $9.5 million. The realized commodity gains in the first half of 2012 reflect the settlement of contracts below the relevant strike prices. In addition, in the first quarter of 2012 we unwound certain natural gas derivative contracts and realized a gain of $41.2 million. Unrealized commodity derivative (gains) losses represent the change in the fair value of our open derivative contracts from period to period. Derivative premiums are amortized over the term of the underlying derivative contracts.

Income Tax Expense (Benefit). Due to our valuation allowance, there was no income tax expense (benefit) recorded in the six month periods ended June 30, 2013 or 2012. 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 or for state income taxes.

Net Income (Loss). Net income for the first half of 2013 was $37.0 million compared to net loss of $13.4 million for the same period in 2012. The change between periods is the result of the items discussed above.

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

Net cash provided by operating activities was $39.5 million in the first half of 2013 compared to net cash provided by operating activities of $99.9 million in the 2012 period. Cash flows used in operating activities in the first half of 2013 as compared to the 2012 period were impacted by increased cash flows from higher oil production offset by cash outflows of $19.7 million for realized commodity derivative losses, higher interest expense of $4.7 million, and greater share-based compensation expense of $10.8 million for cash settled awards. Cash flows from operating activities in the first half of 2012 were favorably impacted by a realized gain of $52.2 million from the early settlement of oil and natural gas derivative contracts.

Net cash provided by investing activities was $52.8 million in the first half of 2013 compared to net cash used in investing activities of $110.1 million in the 2012 period. The primary investing activities in the first half of 2013 were sales proceeds of $101 million received as a result of the Sacramento Basin asset sale, partially offset by $46 million in capital expenditures on oil properties related to our capital expenditure program. The primary investing activities in the first half of 2012 were $132 million in capital expenditures on oil and natural gas properties related to our capital expenditure program, partially offset by $23 million in net cash proceeds received from the sale of our Santa Clara Avenue field in the second quarter of 2012.

Net cash used in financing activities was $142.6 million in the first half of 2013 compared to net cash provided by financing activities of $2.0 million during the 2012 period. The primary financing activities in the first half of 2013 were (i) repayment of $315 million on our second lien term loan with a combination of Sacramento Basin asset sale proceeds of $208 million and borrowings on our revolving credit facility of $107 million and (ii) net additional borrowings of $76 million on our revolving credit facility. The primary financing activities in the first half of 2012 were $2 million in net borrowings under our revolving credit facility.

We plan to make substantial capital expenditures in the future for the acquisition, exploration, exploitation and development of oil and natural gas properties. Our 2013 exploration, exploitation and development capital expenditures budget is currently $91 million and through the first half of 2013, we have incurred $43 million. We expect to fund these expenditures primarily with cash flow from operations, supplemented with borrowings under our revolving credit facility. We have significant flexibility to reduce capital expenditures if warranted by business conditions or limits on our capital resources. We are pursuing various deleveraging transactions and are considering others. Deleveraging transactions may include the formation of a master limited partnership, debt refinancings, 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.

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 drilling and other development activities, 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. In addition, our sole stockholder incurred $60 million of indebtedness in connection with the going private transaction, and is required to make periodic interest payments on such indebtedness. These payments may be made in the form of additional indebtedness or in cash. If our stockholder causes us to make cash dividends to allow it to make its interest payments in cash, our need for capital would be increased; however, our debt agreements limit our ability to pay cash dividends.

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 and the minimum interest coverage ratio (as defined in the agreement) is 1.75 to 1.00. In March 2013, we entered into an amendment to the revolving credit agreement pursuant to which, among other things, the maximum ratio of debt to EBITDA was changed to 5.75 to 1.00 through September 30, 2013, stepping down over time to 4.00 to 1.00 by September 30, 2014. As amended, the agreement also requires that our ratio of secured debt (as defined) to EBITDA not exceed 2.00 to 1.00 if the ratio of total debt to EBITDA exceeds 3.75 to 1.00. In addition, the amendment increased the borrowing base under the facility from $175 million to $270 million. We borrowed an additional $107 million under the facility contemporaneously with entering into the amendment, and used those funds to repay all amounts outstanding under the second lien term loan facility. 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. See also Note 1 to the accompanying financial statements. 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 $268.0 million and our borrowing base which, as discussed above, is currently established at $270.0 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 ten 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 August 1, 2013, we had $173.0 million outstanding under the facility at an average interest rate of 3.25% and $91.4 million in available borrowing capacity, net of the outstanding balance and $3.6 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. In the first quarter of 2013, we applied Sacramento Basin sales proceeds to prepay $214.7 million in principal outstanding under the second lien term loan and $6.4 million in prepayment penalties, and we then used

$107.0 million of additional borrowings under the revolving credit facility to repay all remaining amounts outstanding under the loan and an additional $3.0 million in prepayment penalties. The agreement contained certain customary covenants, including covenants that restricted the Company's ability to incur additional indebtedness and financial covenants that required the Company to maintain specified ratios of debt to adjusted EBITDA, interest coverage and collateral coverage. The term loan facility was secured by a second priority lien on substantially all of our assets.

Loans made under the second lien term loan facility were designated, at our option, as either "Base Rate Loans" or "LIBO Rate Loans." Loans designated as Base Rate Loans bore interest at a floating rate equal to (i) the greater of (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 bore interest at LIBOR plus 7.00%. Per the second lien term loan agreement, LIBOR was to be not 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 the second lien term loan then in place. 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 notes pay interest semi-annually in arrears on April 1 and October 1 of each year. We may redeem the 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 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 in connection with the going private transaction has increased the debt-related risks we face, 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.

At June 30, 2013, we had no existing off-balance sheet arrangements, as defined under SEC rules, that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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."

Commodity Derivative Agreements. In January 2013, in connection with the Sacramento Basin asset sale, we settled all of our natural gas derivative contracts and natural gas basis swaps, paying $3.8 million. Also in January 2013, we settled 25% of our NYMEX/Brent basis swaps, paying $2.1 million. In April 2013, we settled the remaining 75% of our NYMEX/Brent basis swaps, paying $3.6 million. As of June 30, 2013, we had entered into various swap, collar and option agreements related to our oil production. The aggregate economic effects of those agreements are summarized below. Location and quality differentials attributable to our properties are not included in the following prices. The agreements provide for monthly settlement based on the differential between the agreement price and the actual Brent price.

From time to time we have also entered into certain oil basis swaps. The swaps fix the differential between the WTI crude price index and Brent. Historically, the two price indexes had 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 Southern California indexes most relevant to us have in recent periods tracked more closely with Brent prices than with WTI. In April 2013, we settled all of our oil basis swaps, paying $3.6 million.

Our portfolio of commodity derivative transactions as of June 30, 2013 is summarized below:

Type of Contract	Counterparty	Basis		Strike Price ($/Bbl)

Collar	Bank of Nova Scotia	Brent	700	$	90.00/$122.70	Jul 1, 13 - Dec 31, 13
Swap	Bank of Nova Scotia	Brent	675	$	106.50	Jul 1, 13 - Dec 31, 13
Swap	Citibank N.A.	Brent	675	$	106.53	Jul 1, 13 - Dec 31, 13
Put	Bank of America	Brent	750		90.00	Jul 1, 13 - Dec 31, 13
Collar	Key Bank	Brent	225	$	90.00/$97.00	Jul 1, 13 - Dec 31, 14
Collar	Key Bank	Brent	200	$	90.00/$93.75	Jan 1, 14 - Dec 31, 14
Put	Citibank N.A.	Brent	575	$	90.00	Jan 1, 14 - Dec 31, 14
Collar	Credit Suisse	Brent	1,000	$	90.00/$98.00	Jul 1, 13 - Dec 31, 15
Collar	Bank of America	Brent	1,000	$	90.00/$101.25	Jul 1, 13 - Dec 31, 15
Collar	Bank of Nova Scotia	Brent	1,675	$	90.00/$98.15	Jul 1, 13 - Dec 31, 15

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 we therefore 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 June 30, 2013, the fair value of our commodity derivatives was a net liability of $2.9 million.

We are subject to interest rate risk with respect to amounts borrowed from time to time under our revolving credit facility because those amounts bear interest at variable rates. 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 $1.8 million on our variable rate borrowings of $183.0 million as of June 30, 2013.

See notes to our consolidated financial statements for a discussion of our long-term debt as of June 30, 2013.

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 June 30, 2013. Based on the evaluation, those officers believe that:

There has not been any change in our internal control over financial reporting that occurred during the quarter ended June 30, 2013 that has materially affected, or is likely to materially affect, our internal control over financial reporting.

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

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, 2012, 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.

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.


ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2013
Or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


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


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


PART I.	FINANCIAL INFORMATION	2
Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets at December 31, 2012 and June 30, 2013	2
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2012 and the Three and Six Months Ended June 30, 2013	3
	Condensed Consolidated Statements of Changes in Stockholders' Equity for the Six Months Ended June 30, 2013	4
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2012 and the Six Months Ended June 30, 2013	5
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	45
Item 4.	Controls and Procedures	47
PART II.	OTHER INFORMATION	48
Item 1.	Legal Proceedings	48
Item 1A.	Risk Factors	48
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	48
Item 3.	Defaults upon Senior Securities	48
Item 4.	Mine Safety Disclosures	48
Item 5.	Other Information	48
Item 6.	Exhibits	48
Signatures		49

	December 31, 2012			June 30, 2013

Revolving credit agreement due March 2016	$	—		$	183,000
Second lien term loan due June 2017 (face value $315,000)		308,960			—
11.50% senior notes due October 2017 (face value $150,000)		144,724			145,145
8.875% senior notes due February 2019 (face value $500,000)		500,000			500,000

Total long-term debt		953,684			828,145
Less: current portion of long-term debt		(104,494	)		—

Long-term debt, net of current portion	$	849,190		$	828,145

	Common Stock							Retained Earnings (Accumulated Deficit)

	Common Stock				Additional Paid-in Capital
	Shares		Amount		Additional Paid-in Capital						Total
BALANCE AT DECEMBER 31, 2012		29,936	$	299	$	124,358		$	(420,315	)	$	(295,658	)
Going private transaction share repurchase costs		—		—		(9	)		—			(9	)
Net income (loss)		—		—		—			36,998			36,998

BALANCE AT JUNE 30, 2013		29,936	$	299	$	124,349		$	(383,317	)	$	(258,669	)

	Oil (Brent)

	Barrels/day		Weighted Avg. Prices per Bbl
July 1 - December 31, 2013:
Swaps		1,350	$	106.52
Collars		4,600	$	90.00/$102.47
Puts		750	$	90.00
January 1 - December 31, 2014:
Collars		4,100	$	90.00/$98.59
Puts		575	$	90.00
January 1 - December 31, 2015:
Collars		3,675	$	90.00/$98.95

	June 30, 2013

	Current Liability		Long Term Liability		Total Liability
Rights to receive	$	13,210	$	—	$	13,210
Restricted share units		1,682		1,345		3,027
Share appreciation rights		413		6,708		7,121
ESOP		—		245		245

Total share-based compensation liability	$	15,305	$	8,298	$	23,603

	Level 1		Level 2			Level 3			Fair Value as of June 30, 2013

Assets (Liabilities):
Commodity derivative contracts	$	—	$	2,606		$	—		$	2,606
Commodity derivative contracts		—		(5,496	)		—			(5,496	)
Share-based compensation		—		—			(10,393	)		(10,393	)

	Six Months Ended June 30,

	2012		2013
Fair value liability, beginning of period	$	—	$	(3,091	)
Transfers into Level 3(1)		—		(8,632	)
Transfers out of Level 3(2)		—		3,248
Change in fair value of Level 3		—		(1,918	)

Fair value liability, end of period	$	—	$	(10,393	)

	December 31, 2012				June 30, 2013

	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Revolving credit agreement	$	—	$	—	$	183,000	$	183,000
Second lien term loan		308,960		322,088		—		—
11.50% senior notes		144,724		155,625		145,145		157,500
8.875% senior notes		500,000		468,625		500,000		489,375

	Three Months Ended June 30,

	2012			2013
General and administrative costs	$	13,579		$	11,175
Share-based compensation costs		1,840			4,940
Going private related costs (none capitalized)		852			—
General and administrative costs capitalized		(6,402	)		(5,740	)

General and administrative expense, net of amounts capitalized	$	9,869		$	10,375

	Three Months Ended June 30,

	2012			2013
Realized commodity derivative losses (gains)	$	(6,786	)	$	5,132
Amortization of commodity derivative premiums		2,224			1,018
Unrealized commodity derivative losses (gains) for changes in fair value		(2,134	)		(26,101	)

Commodity derivative losses (gains), net	$	(6,696	)	$	(19,951	)

	Six Months Ended June 30,

	2012			2013
	(in thousands)
Cash (used in) provided by operating activities	$	99,931		$	39,495
Cash (used in) provided by investing activities		(110,117	)		52,769
Cash (used in) provided by financing activities		2,040			(142,566	)

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 June 30, 2013, 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.


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