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

Form 10-Q

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

Commission File ~~Number~~Numbers: Venoco, Inc. 333-123711 Denver Parent Corporation 333-191602

Venoco, Inc. Denver Parent Corporation

Delaware (State or other jurisdiction of incorporation or organization)		77-0323555 (I.R.S. Employer Identification Number)
Delaware Delaware (State or other jurisdiction of incorporation or organization)		77-0323555 44-0821005 (I.R.S. Employer Identification Number)
370 17th Street, Suite 3900 Denver, Colorado (Address of principal executive offices)		80202-1370 (Zip Code)

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

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

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

~~Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site~~Venoco, ~~if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232~~Inc.~~405~~ ofYES ~~this~~o ~~chapter)~~NO ~~during~~ý ~~the~~Denver ~~preceding~~Parent ~~12 months~~Corporation ~~(or~~YES ~~for~~o ~~such shorter period that the registrant was required to submit and post such files). YES ý~~ NO o 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).


Venoco, Inc.	YES ý	NO o
Denver Parent Corporation	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.

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

~~Indicate by~~Denver ~~check~~Parent ~~mark~~Corporation ~~whether~~Large ~~the~~accelerated ~~registrant~~filer iso aAccelerated ~~shell~~filer ~~company~~o Non-accelerated filer ý (asDo ~~defined~~not incheck ~~Rule 12b-2~~if ofa ~~the~~smaller ~~Exchange Act~~reporting company)~~. YES o NO ý~~ Smaller reporting company o

On Indicate ~~October 3,~~by ~~2012,~~check mark whether the ~~issuer~~registrant ~~completed~~is a ~~going~~shell ~~private~~company ~~transaction~~ (as adefined ~~result~~in Rule 12b-2 of ~~which its common stock is currently held by a single stockholder and was deregistered under~~ the ~~Securities~~ Exchange Act ~~of 1934~~).


Venoco, Inc.	YES o	NO ý
Denver Parent Corporation	YES o	NO ý

As of November 12, 2013, there were 30,150,933 shares of common stock Denver Parent Corporation and 29,936,378 shares of common stock of Venoco, Inc. outstanding.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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~~in the Venoco, Inc. 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~~the Venoco, Inc. Annual Report on Form 10-K for the year ended December 31, 2012 and such things as:

•: changes in oil and natural gas prices, including reductions in prices that would adversely affect our revenues, income, cash flow from operations, liquidity and reserves;
•: adverse conditions in global credit markets and in economic conditions generally;
•: risks relating to the concentration of our properties in a limited number of areas in California;
•: risks related to our indebtedness, and a potential inability to effect deleveraging transactions or otherwise reduce those risks;
•: our ability to replace our reserves;
•: risks arising out of our hedging transactions;
•: our inability to access oil and natural gas markets due to operational impediments;
•: uninsured or underinsured losses in, or operational problems affecting, our operations;
•: inaccuracy in reserve estimates and expected production rates;
•: risks associated with litigation, arbitration or other legal proceedings that we are involved in, including the costs of participating in those proceedings and the risk of adverse outcomes;
•: exploitation, development and exploration results, including in the onshore Monterey shale, where our results will depend on, among other things, our ability to identify productive intervals and drilling and completion techniques necessary to achieve commercial production from those intervals;
•: the consequences of changes we have made, or may make from time to time in the future, to our capital expenditure budget, including the impact of those changes on our production levels, reserves, results of operations and liquidity;
•: our ability to manage expenses, including expenses associated with asset retirement obligations;
•: a lack of available capital and financing, including as a result of a reduction in the borrowing base under our revolving credit facility;
•: the potential unavailability of drilling rigs and other field equipment and services;
•: the existence of unanticipated liabilities or problems relating to acquired businesses or properties;

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•: difficulties involved in the integration of operations we have acquired or may acquire in the future;
•: the effect of any business combination, joint venture or other significant transaction we may pursue, or the costs of litigation related thereto, and purchase price or other adjustments in connection with such transactions that may be unfavorable to us;
•: factors affecting the nature and timing of our capital expenditures;
•: the impact and costs related to compliance with or changes in laws or regulations governing or affecting our operations, including changes resulting from the Deepwater Horizon well blowout in the Gulf of Mexico, from the Dodd-Frank Wall Street Reform and Consumer Protection Act or its implementing regulations and from regulations relating to greenhouse gas emissions;
•: delays, denials or other problems relating to our receipt of operational consents and approvals from governmental entities and other parties;
•: environmental liabilities;
•: loss of senior management or technical personnel;
•: natural disasters, including severe weather;
•: acquisitions and other business opportunities (or the lack thereof) that may be presented to and pursued by us;
•: risk factors discussed in this report; and
•: other factors, many of which are beyond our control.

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~~VENOCO, INC.~~ ~~Form 10-Q~~ ~~for the Quarterly Period Ended June 30, 2013~~ Explanatory Note

This Quarterly Report on Form 10-Q is a combined report being filed by Denver Parent Corporation ("DPC") and Venoco, Inc. ("Venoco"), a direct 100% owned subsidiary of DPC. DPC is a holding company formed to acquire all of the common stock of Venoco in a going private transaction that was completed in October 2012. Unless otherwise indicated or the context otherwise requires, (i) references to "DPC" refer only to DPC, (ii) references to the "Company," "we," "our" and "us" refer, for periods following the going private transaction, to DPC and its subsidiaries, including Venoco and its subsidiaries, and for periods prior to the going private transaction, to Venoco and its subsidiaries and (iii) references to "Venoco" refer to Venoco and its subsidiaries. Each registrant included herein is filing on its own behalf all of the information contained in this quarterly report that pertains to such registrant. When appropriate, disclosures specific to DPC or Venoco are identified as such. Each registrant included herein is not filing any information that does not relate to such registrant, and therefore makes no representation as to any such information. Where the information provided is substantially the same for both companies, such information has been combined. Where information is not substantially the same for both companies, we have provided separate information. In addition, separate financial statements for each company are included in Part I, Item 1, "Financial Statements."

We operate DPC and Venoco as one business, with one management team. Management believes combining the Quarterly Reports on Form 10-Q of DPC and Venoco provides the following benefits:

•: Enhances investors' understanding of DPC and Venoco by enabling investors to view the business as a whole, the same manner management views and operates the business;
•: Provides a more readable presentation of required disclosures with less duplication, since a substantial portion of the disclosures apply to both DPC and Venoco; and
•: Creates time and cost efficiencies through the preparation of one combined report instead of two separate reports.

All of Venoco's net assets are owned by DPC and all of DPC's operations are conducted by Venoco.

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VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION AND SUBSIDIARIES
Form 10-Q for the Quarterly Period Ended September 30, 2013

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PART I.	FINANCIAL INFORMATION	2	2
Item 1.	Financial Statements (Unaudited)	2
	Condensed Consolidated Balance Sheets at December 31, 2012 and June 30, 2013		2
	Condensed Consolidated Balance Sheets at December 31, 2012 and September 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 Operations for the Three and Nine Months Ended September 30, 2012 and the Three and Nine Months Ended September 30, 2013	3
	Condensed Consolidated Statements of Changes in Stockholders' Equity for the Six Months Ended June 30, 2013		4
	Condensed Consolidated Statements of Changes in Stockholders' Equity for the Nine Months Ended September 30, 2013	5
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2012 and the Six Months Ended June 30, 2013		5
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and the Nine Months Ended September 30, 2013	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	33	31
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	49	45
Item 4.	Controls and Procedures	52	47
PART II.	OTHER INFORMATION	53	48
Item 1.	Legal Proceedings	53	48
Item 1A.	Risk Factors	53	48
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53	48
Item 3.	Defaults upon Senior Securities	53	48
Item 4.	Mine Safety Disclosures	53	48
Item 5.	Other Information	53	48
Item 6.	Exhibits	53	48
Signatures		55	49

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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 AND DENVER PARENT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(In thousands, except shares)

	Venoco, Inc.						Denver Parent Corporation

	December 31, 2012			September 30, 2013			December 31, 2012			September 30, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	53,818		$	16		$	54,318		$	17,240
Accounts receivable		108,356			26,171			108,356			25,828
Inventories		5,101			5,380			5,101			5,380
Other current assets		4,448			5,322			4,519			5,338
Commodity derivatives		153			1,346			153			1,346

Total current assets		171,876			38,235			172,447			55,132

PROPERTY, PLANT AND EQUIPMENT, AT COST:
Oil and gas properties, full cost method of accounting
Proved		1,927,259			1,966,138			1,927,259			1,966,138
Unproved		16,165			14,256			16,165			14,256
Accumulated depletion		(1,311,898	)		(1,346,311	)		(1,311,898	)		(1,346,311	)

Net oil and gas properties		631,526			634,083			631,526			634,083
Other property and equipment, net of accumulated depreciation and amortization of $15,176 and $15,464 at December 31, 2012 and September 30, 2013, respectively		17,076			16,566			17,076			16,566

Net property, plant and equipment		648,602			650,649			648,602			650,649

OTHER ASSETS:
Commodity derivatives		—			445			—			445
Deferred loan costs		21,569			12,521			24,820			17,772
Other		4,034			5,749			4,034			5,817

Total other assets		25,603			18,715			28,854			24,034

TOTAL ASSETS	$	846,081		$	707,599		$	849,903		$	729,815

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt	$	104,494		$	—		$	104,494		$	—
Accounts payable and accrued liabilities		57,315			41,494			57,315			41,584
Interest payable		27,862			6,319			27,862			10,170
Commodity derivatives		20,607			7,002			20,607			7,002
Share-based compensation		10,424			15,123			10,424			15,123

Total current liabilities		220,702			69,938			220,702			73,879

LONG-TERM DEBT		849,190			708,521			909,190			956,770
COMMODITY DERIVATIVES		20,287			7,589			20,287			7,589
ASSET RETIREMENT OBLIGATIONS		41,119			35,307			41,119			35,307
SHARE-BASED COMPENSATION		10,441			5,239			10,441			5,239

Total liabilities		1,141,739			826,594			1,201,739			1,078,784

COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Common stock, $.01 par value (200,000,000 shares authorized for Venoco and DPC; 29,936,378 Venoco shares issued and outstanding at December 31, 2012 and September 30, 2013; 29,936,378 and 30,150,933 DPC shares issued and outstanding at December 31, 2012 and September 30, 2013)		299			299			299			301
Additional paid-in capital		124,358			282,734			68,421			71,518
Retained earnings (accumulated deficit)		(420,315	)		(402,028	)		(420,556	)		(420,788	)

Total stockholders' equity		(295,658	)		(118,995	)		(351,836	)		(348,969	)

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	846,081		$	707,599		$	849,903		$	729,815

See notes to condensed consolidated financial statements.

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VENOCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(In thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2013			2012			2013
REVENUES:
Oil and natural gas sales	$	8095,~~936~~377		$	8179,~~449~~696		$	~~164~~259,~~324~~701		$	~~167~~247,~~408~~104
Other		1,~~563~~321			~~910~~1,249			34,~~538~~859			23,~~214~~463
Total revenues		8296,~~499~~698			8280,~~359~~945			~~167~~264,~~862~~560			~~169~~250,~~622~~567
EXPENSES:
Lease operating expense		2022,~~093~~899			1718,~~914~~274			4467,~~543~~442			3654,~~445~~719
Property and production taxes		51,~~302~~671			~~1,407~~(472	)		68,~~917~~588			2,~~534~~062
Transportation expense		~~257~~482			4550			45,~~669~~151			83133
Depletion, depreciation and amortization		2122,~~213~~240			12,~~406~~551			4365,~~467~~707			2336,~~978~~529
Accretion of asset retirement obligations		1,~~450~~457			~~615~~595			24,~~841~~298			1,~~271~~866
General and administrative, net of amounts capitalized		911,~~869~~822			105,~~375~~358			2234,~~230~~052			2530,~~350~~708
Total expenses		5860,~~184~~571			4236,~~762~~356			~~124~~185,~~667~~238			89126,~~661~~017
Income from operations		2436,~~315~~127			3944,~~597~~589			4379,~~195~~322			79124,~~961~~550
FINANCING COSTS AND OTHER:
Interest expense, net		1516,~~880~~498			1715,~~401~~674			3148,~~591~~089			3651,~~255~~929
Amortization of deferred loan costs		~~585~~597			~~906~~868			1,~~154~~751			2,~~019~~887
Loss on extinguishment of debt		—			—16,787			—			2138,~~297~~084
Commodity derivative losses (gains), net		(649,~~696~~089	)		~~(19~~14,~~951~~171	)		2372,~~842~~931			(162,~~608~~437	)
Total financing costs and other		966,~~769~~184			(147,~~644~~500	)		56122,~~587~~771			4290,~~963~~463
Income (loss) before income taxes		14(30,~~546~~057	)		41(2,~~241~~911	)		(1343,~~392~~449	)		3634,~~998~~087
Income tax provision (benefit)		—			—			—			—
Net income (loss)	$	14(30,~~546~~057	)	$	41(2,~~241~~911	)	$	(1343,~~392~~449	)	$	3634,~~998~~087

See notes to condensed consolidated financial statements.

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~~VENOCO, INC.~~DENVER PARENT CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF ~~CHANGES~~OPERATIONS ~~IN STOCKHOLDERS' EQUITY~~ (UNAUDITED) (In thousands)

	Common Stock									Retained Earnings (Accumulated Deficit)
	Three Months Ended September 30,						Nine Months Ended September 30,
							Additional Paid-in Capital
	2012			2013			2012			2013
	Shares			Amount									Total
REVENUES:
BALANCE AT DECEMBER 31, 2012		29,936		$	299		$	124,358		$	(420,315	)	$	(295,658	)
Oil and natural gas sales	$	95,377		$	79,696		$	259,701		$	247,104
Going private transaction share repurchase costs		—			—			(9	)		—			(9	)
Other		1,321			1,249			4,859			3,463
Net income (loss)		—			—			—			36,998			36,998
Total revenues		96,698			80,945			264,560			250,567
BALANCE AT JUNE 30, 2013		29,936		$	299		$	124,349		$	(383,317	)	$	(258,669	)
EXPENSES:
Lease operating expense		22,899			18,274			67,442			54,719
Property and production taxes		1,671			(472	)		8,588			2,062
Transportation expense		482			50			5,151			133
Depletion, depreciation and amortization		22,240			12,551			65,707			36,529
Accretion of asset retirement obligations		1,457			595			4,298			1,866
General and administrative, net of amounts capitalized		11,822			5,389			34,052			30,869
Total expenses		60,571			36,387			185,238			126,178
Income from operations		36,127			44,558			79,322			124,389
FINANCING COSTS AND OTHER:
Interest expense, net		16,498			21,111			48,089			65,329
Amortization of deferred loan costs		597			1,150			1,751			3,722
Loss on extinguishment of debt		—			36,710			—			58,007
Commodity derivative losses (gains), net		49,089			14,171			72,931			(2,437	)
Total financing costs and other		66,184			73,142			122,771			124,621
Income (loss) before income taxes		(30,057	)		(28,584	)		(43,449	)		(232	)
Income tax provision (benefit)		—			—			—			—
Net income (loss)	$	(30,057	)	$	(28,584	)	$	(43,449	)	$	(232	)

See notes to condensed consolidated financial statements.

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VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF ~~CASH~~CHANGES ~~FLOWS~~IN STOCKHOLDERS' EQUITY (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

	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	)
DPC capital contribution to Venoco		—		—		158,385			—			158,385
Dividend to DPC		—		—		—			(15,800	)		(15,800	)
Net income (loss)		—		—		—			34,087			34,087

BALANCE AT SEPTEMBER 30, 2013		29,936	$	299	$	282,734		$	(402,028	)	$	(118,995	)

DENVER PARENT CORPORATION AND SUBSIDIARIES

	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	$	68,421		$	(420,556	)	$	(351,836	)
Going private transaction share repurchase costs		—		—		(9	)		—			(9	)
Capital contribution		—		—		3,108			—			3,108
Issuance of shares to ESOP		215		2		(2	)		—			—
Net income (loss)		—		—		—			(232	)		(232	)

BALANCE AT SEPTEMBER 30, 2013		30,151	$	301	$	71,518		$	(420,788	)	$	(348,969	)

See notes to condensed consolidated financial statements.

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VENOCO, INC. AND SUBSIDIARIES ~~NOTES~~ TOAND DENVER PARENT CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED ~~FINANCIAL~~ STATEMENTS OF CASH FLOWS (UNAUDITED) (In thousands)

1. SIGNIFICANT ACCOUNTING POLICIES

	Venoco, Inc.						Denver Parent Corporation

	Nine Months Ended September 30,						Nine Months Ended September 30,
	2012			2013			2012			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(43,449	)	$	34,087		$	(43,449	)	$	(232	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization		65,707			36,529			65,707			36,529
Accretion of asset retirement obligations		4,298			1,866			4,298			1,866
Share-based compensation		4,245			—			4,245			—
Interest paid-in-kind		—			—			—			5,005
Amortization of deferred loan costs		1,751			2,887			1,751			3,722
Loss on extinguishment of debt		—			38,084			—			58,007
Amortization of bond discounts and other		566			698			566			822
Unrealized commodity derivative (gains) losses and amortization of premiums		113,216			(26,447	)		113,216			(26,447	)
Changes in operating assets and liabilities:
Accounts receivable		(3,800	)		9,368			(3,800	)		9,711
Inventories		1,438			(279	)		1,438			(279	)
Other current assets		(909	)		(1,027	)		(909	)		(1,037	)
Other assets		(2,616	)		(1,715	)		(2,616	)		(1,783	)
Accounts payable and accrued liabilities		4,860			(30,190	)		4,860			(26,249	)
Share-based compensation liabilities		—			(503	)		—			(503	)
Net premiums paid on derivative contracts		(10,987	)		(1,494	)		(10,987	)		(1,494	)

Net cash provided by (used in) operating activities		134,320			61,864			134,320			57,638

CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties		(176,734	)		(78,628	)		(176,734	)		(78,628	)
Acquisitions of oil and natural gas properties		(175	)		(45	)		(175	)		(45	)
Expenditures for other property and equipment		(2,399	)		(2,243	)		(2,399	)		(2,243	)
Proceeds from sale of oil and natural gas properties		23,342			100,305			23,342			100,305

Net cash provided by (used in) investing activities		(155,966	)		19,389			(155,966	)		19,389

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		200,000			399,900			200,000			648,025
Principal payments on long-term debt		(168,000	)		(656,379	)		(168,000	)		(721,384	)
Premium paid to pay down debt		—			(19,905	)		—			(36,626	)
Payments for deferred loan costs		(444	)		(1,247	)		(444	)		(7,219	)
Proceeds from stock incentive plans and other		133			—			133			—
Going private share repurchase costs		—			(9	)		—			(9	)
DPC capital contribution to Venoco		—			158,385			—			3,108
Dividend to DPC		—			(15,800	)		—			—

Net cash provided by (used in) financing activities		31,689			(135,055	)		31,689			(114,105	)

Net (decrease) increase in cash and cash equivalents		10,043			(53,802	)		10,043			(37,078	)
Cash and cash equivalents, beginning of period		8,165			53,818			8,165			54,318

Cash and cash equivalents, end of period	$	18,208		$	16		$	18,208			17,240

Supplemental Disclosure of Cash Flow Information—
Cash paid for interest	$	54,529		$	72,775		$	54,529		$	77,195
Cash paid (received) for income taxes	$	—		$	—		$	—		$	—
Supplemental Disclosure of Noncash Activities—
(Decrease) increase in accrued capital expenditures	$	865		$	(7,174	)	$	865		$	(7,174	)

~~Description of Operations Venoco, Inc. ("our," "us," "Venoco" or the "Company"), a Delaware corporation, is engaged in the~~ ~~acquisition, exploration,~~See ~~exploitation~~notes ~~and~~to ~~development~~condensed ofconsolidated ~~oil~~financial ~~and natural gas properties with a focus on properties offshore and onshore in California~~statements.

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

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

1. SIGNIFICANT ACCOUNTING POLICIES

Description of Operations Denver Parent Corporation ("DPC"), a Delaware corporation, was formed in January, 2012 for the purpose of acquiring all of the outstanding common stock of Venoco, Inc. (see below) and has no other operations. Venoco, Inc. ("Venoco"), a Delaware corporation, is a wholly-owned subsidiary of DPC and is engaged in the acquisition, exploration and development of oil and natural gas properties with a focus on properties offshore and onshore in California.

Basis of Presentation This Quarterly Report on Form 10-Q is a combined report being filed by DPC and Venoco. Unless otherwise indicated or the context otherwise requires, (i) references to "DPC" refer only to DPC, (ii) references to the "Company," "we," "our" and "us" refer, for periods following the going private transaction, to DPC and its subsidiaries, including Venoco and its subsidiaries, and for periods prior to the going private transaction, to Venoco and its subsidiaries and (iii) references to "Venoco" refer to Venoco and its subsidiaries. Each registrant included herein is filing on its own behalf all of the information contained in this quarterly report that pertains to such registrant. When appropriate, disclosures specific to DPC and Venoco are identified as such. Each registrant included herein is not filing any information that does not relate to such registrant, and therefore makes no representation as to any such information. Where the information provided is substantially the same for both companies, such information has been combined. Where information is not substantially the same for both companies, we have provided separate information. In addition, separate financial statements for each company are included in this report.

The unaudited condensed consolidated financial statements include the accounts of DPC and its subsidiaries, and Venoco and its subsidiaries. All such subsidiaries 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.

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VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

Liquidity The Company was in compliance with all debt covenants at September 30, 2013. However, the additional indebtedness that the Company ~~may~~incurred ~~require~~in ~~recognition~~connection orwith ~~disclosure~~the ingoing ~~these~~private transaction and the associated financial ~~statements.~~covenants in Venoco's ~~Annual~~revolving ~~Report~~credit onfacility, ~~Form 10~~which step down over time, has increased debt-Krelated ~~for~~risks. These include risks that the ~~year~~Company ~~ended~~may ~~December 31~~default on its obligations under its debt agreements, ~~2012~~that ~~includes~~its ~~certain~~ability ~~definitions~~to replace reserves and ~~a summary~~maintain ofits ~~significant~~production ~~accounting~~may ~~policies~~be adversely affected by capital constraints and ~~should~~the financial covenants under its debt agreements and that the Company may be ~~read~~more vulnerable to adverse changes in ~~conjunction~~commodity ~~with~~prices ~~this~~and ~~report~~other operational risks and economic conditions. ~~The~~Venoco ~~results~~recently ~~for~~amended ~~interim~~its revolving credit facility to include more favorable financial covenant requirements in future periods. ~~are~~However, ~~not~~we ~~necessarily~~currently ~~indicative~~project ofthat ~~annual~~the ~~results~~margin by which Venoco will be in compliance with certain covenants, particularly the debt-to-EBITDA covenant in its revolving credit agreement, will narrow after September 30, 2013. Due to various operational risks and commodity pricing risks, there can be no assurances that Venoco will remain in compliance with this covenant or other covenants in its debt agreements.

~~In the~~ Income ~~course~~Taxes The ofcompany ~~preparing~~computes ~~the~~its ~~condensed~~quarterly ~~consolidated~~taxes ~~financial~~under ~~statements,~~the ~~management~~effective ~~makes~~tax ~~various~~rate ~~assumptions,~~method ~~judgments~~based ~~and~~on ~~estimates~~applying toan ~~determine the reported amount of assets,~~anticipated ~~liabilities,~~annual ~~revenue~~effective ~~and~~rate ~~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~~to ~~occurrence~~its ofyear-to-date ~~future~~income ~~events~~or ~~and~~loss, ~~accordingly,~~except ~~actual~~for ~~results~~discrete ~~could differ from amounts initially established~~items. ~~Significant~~Income ~~areas~~taxes ~~requiring~~for ~~the~~discrete ~~use~~items ofare ~~assumptions,~~computed ~~judgments~~ and ~~estimates~~recorded ~~include (1) oil and gas reserves; (2) cash flow estimates used~~ in ~~ceiling~~the ~~tests~~period ~~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~~which ~~with~~the ~~business~~specific ~~combinations;~~transaction ~~(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~~occurs. ~~Although management believes these estimates are reasonable, actual results could differ from these estimates.~~

~~Income~~ Venoco has ~~Taxes The~~net ~~Company~~operating ~~computes~~loss ~~its~~carryovers ~~quarterly~~as of December 31, 2012 of $398.4 million for federal income tax purposes as a result of losses incurred before income taxes ~~under~~in 2008, 2009 and 2012 as well as taxable losses in each of the ~~effective~~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 ~~rate~~assets ~~method~~at ~~based~~December 31, 2012 and September 30, 2013 since it cannot conclude that it is more likely than not that its net deferred tax assets will be fully realized on ~~applying~~future anincome ~~anticipated~~tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which ~~annual~~those ~~effective~~temporary ~~rate~~differences tobecome 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 ~~year-~~net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-~~date~~tax ~~income~~earnings; consistent and sustained pre-tax earnings; sustained or ~~loss~~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, ~~except~~meaningful ~~for~~production ~~discrete~~and proved ~~items.~~reserves ~~Income~~from ~~taxes~~the ~~for~~Company's ~~discrete~~onshore ~~items~~Monterey ~~are~~shale ~~computed~~project; meaningful production and ~~recorded~~proved inreserves from the ~~period~~CO2 inproject ~~which~~at the ~~specific~~Hastings ~~transaction~~Complex; ~~occurs~~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.

~~The~~As ~~Company~~long ~~has net operating loss carryovers~~ as ofthe ~~December 31,~~Company ~~2012~~concludes ofthat ~~$394.5 million~~it ~~for~~will ~~federal~~continue ~~income~~to ~~tax~~have ~~purposes as~~ a ~~result~~need offor 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~~the ~~and~~Company ~~June 30, 2013 since it cannot conclude that it is more~~ likely ~~than~~will not ~~that~~have ~~its~~any ~~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~~expense 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~~benefit ~~evidence~~other ~~which may lead the Company to conclude that it is more likely~~ than ~~not~~for ~~that~~federal ~~its~~alternative ~~net deferred~~minimum tax ~~assets will be realized include~~expense, ~~but~~a ~~are~~release ~~not~~of ~~limited~~a ~~to,~~portion ~~cumulative~~of 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~~valuation ~~development~~allowance ~~efforts~~for atnet ~~its~~operating ~~Southern~~loss ~~California~~carryback ~~legacy~~claims 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~~for ~~deleveraging~~state ~~transactions.~~income ~~The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods~~taxes.

~~As long~~ Recently asIssued ~~the~~Accounting ~~Company~~Standards In ~~concludes~~December ~~that~~2011, itthe ~~will~~FASB ~~continue~~issued toAccounting ~~have~~Standards aUpdate ~~need for a full valuation allowance against its net deferred tax assets~~No. 2011-11, ~~the~~ Balance ~~Company~~Sheet ~~likely~~(Topic ~~will~~210) ~~not~~Disclosures ~~have~~about ~~any~~Offsetting ~~income~~Assets ~~tax~~and Liabilities ~~expense~~

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VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

1. SIGNIFICANT ACCOUNTING POLICIES (Continued)

("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 ~~benefit~~an ~~other~~agreement ~~than~~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 ~~federal~~annual ~~alternative~~reporting ~~minimum~~periods ~~tax~~beginning ~~expense~~on or after January 1, a2013, ~~release~~and ofinterim aperiods ~~portion~~within those annual periods. The adoption of ~~the~~this ~~valuation~~authoritative ~~allowance~~guidance ~~for~~did ~~net~~not ~~operating~~have ~~loss~~an ~~carryback~~impact ~~claims~~on the Company's financial position or ~~for~~results ~~state~~of operations, ~~income~~other ~~taxes~~than enhanced disclosures regarding its derivative instruments.

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.

2. SALES OF PROPERTIES

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~~was ~~been~~ released to the Company as of June 30, 2013. The Company ~~applied~~ 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.

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VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

3. LONG-TERM DEBT

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

	December 31, 2012			June 30, 2013
	Venoco, Inc.					Denver Parent Corporation
Revolving credit agreement due March 2016	$	—		$	183,000
	December 31, 2012			September 30, 2013		December 31, 2012			September 30, 2013
Second lien term loan due June 2017 (face value $315,000)		308,960			—
Revolving credit agreement due March 2016	$	—		$	208,000	$	—		$	208,000
11.50% senior notes due October 2017 (face value $150,000)		144,724			145,145
Second lien term loan due June 2017 (face value $315,000)		308,960			—		308,960			—
8.875% senior notes due February 2019 (face value $500,000)		500,000			500,000
11.50% senior notes due October 2017 (face value $150,000)		144,724			521		144,724			521
Total long-term debt		953,684			828,145
8.875% senior notes due February 2019 (face value $500,000)		500,000			500,000		500,000			500,000
Less: current portion of long-term debt		(104,494	)		—
Secured notes due October 2015		—			—		60,000			—
Long-term debt, net of current portion	$	849,190		$	828,145
12.25% / 13.00% senior PIK toggle notes due 2018		—			—		—			248,249
Total long-term debt		953,684			708,521		1,013,684			956,770
Less: current portion of long-term debt		(104,494	)		—		(104,494	)		—
Long-term debt, net of current portion	$	849,190		$	708,521	$	909,190		$	956,770

~~Revolving Credit Facility. In March 2013, the Company entered into an amendment to the fifth amended and restated credit agreement~~ The ~~which~~following ~~maintained the~~summarizes ~~maximum size of its revolving credit facility at $500 million and~~ the ~~maturity~~terms ~~date~~ of the ~~facility~~agreements atgoverning ~~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~~debt 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)~~September ~~the administrative agent's announced prime rate~~30, ~~(y) the~~ ~~federal funds rate plus 0~~2013.~~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.

9 Venoco Revolving Credit Facility. In March 2013, Venoco 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. The borrowing base, which is subject to redetermination twice each year, and may be redetermined at other times at Venoco's request or at the request of the lenders, is currently $270 million. The availability under the facility is limited to the commitments of the participating lenders, which total $268 million. The credit facility is secured by a first priority lien on substantially all of Venoco's oil and natural gas properties and other assets, including the equity interests in all of its subsidiaries, and is unconditionally guaranteed by each of those subsidiaries other than Ellwood Pipeline, Inc. The collateral also secures Venoco'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 our 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 Venoco'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 Venoco's ability to incur

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3. LONG-TERM DEBT (Continued)

~~The~~indebtedness ~~borrowing~~and ~~base~~financial ~~under~~covenants ~~the~~that ~~revolving~~require ~~credit~~Venoco ~~facility~~to ~~has~~maintain ~~been~~specified ~~allocated~~ratios atof ~~various~~current ~~percentages~~assets to acurrent ~~syndicate~~liabilities, ofdebt ~~banks.~~to AsEBITDA, ofsecured ~~August 1,~~debt ~~2013,~~to ~~the~~EBITDA ~~Company~~and ~~had $173~~interest coverage.~~0 million~~ ~~outstanding~~The agreement onalso restricts the ~~facility~~amount ~~and~~of ~~had~~exploratory ~~available~~capital ~~borrowing~~expenditures ~~capacity~~Venoco ofcan ~~$91.4 million~~incur ~~under~~related to the ~~facility,~~onshore ~~net~~Monterey ofproject when the ~~outstanding~~debt ~~balance~~to ~~and~~EBITDA $ratio exceeds 3.~~6 million~~75 into ~~outstanding letters of credit~~1.00.

~~Second~~ The borrowing ~~Lien~~base ~~Term~~under ~~Loan Facility. In connection with~~ the ~~going~~revolving ~~private~~credit ~~transaction, the Company entered into a $315.0 million senior secured second lien term loan~~ facility inhas ~~October~~been ~~2012~~allocated ~~(the~~at ~~"second~~various ~~lien~~percentages ~~term~~to ~~loan~~a ~~facility"),~~syndicate ~~which was issued at 98%~~ of ~~the~~banks. ~~principal~~As ~~amount~~ of ~~the~~November 12, ~~facility.~~2013, ~~The~~Venoco ~~Company~~had ~~repaid~~ $~~214~~213.70 million ~~of the~~ outstanding ~~principal~~on ~~amount under~~ the facility, and ~~$6.4 million~~had inavailable ~~prepayment~~borrowing ~~penalties,~~capacity ~~in the first quarter~~ of ~~2013 with proceeds from the Sacramento Basin asset sale. In March 2013, it used~~ $~~107~~51.4 million ~~of additional borrowings~~ under the ~~revolving credit~~ facility, tonet ~~repay~~of ~~all~~the ~~remaining amounts~~ outstanding ~~under~~balance ~~the facility~~ and $3.06 million in ~~prepayment~~outstanding ~~penalties. Loans~~letters 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~~credit.~~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~~On ~~agreement~~August 20, ~~governing~~2013, ~~the~~Venoco ~~second~~entered ~~lien~~into ~~term~~an ~~loan~~amendment ~~facility~~to ~~contained~~the ~~customary~~revolving ~~representations,~~credit ~~warranties,~~facility ~~events~~to ofincrease ~~default,~~its ~~covenants~~ability ~~and~~to ~~indemnities~~pay dividends to DPC. The ~~facility~~amendment ~~was~~generally ~~secured~~permits byVenoco, ~~second~~subject ~~priority~~to ~~liens~~certain onconditions, ~~substantially~~to ~~all~~pay ofcash ~~the~~dividends ~~Company's~~to ~~oil~~DPC ~~and~~up ~~natural~~to ~~gas~~a ~~properties~~maximum ~~and~~amount ~~other~~of ~~assets,~~$35 million ~~including the equity interests~~ in ~~all~~a offour-quarter ~~its~~period ~~subsidiaries,~~on ~~and~~a ~~was~~rolling ~~unconditionally guaranteed~~basis. byIn ~~each~~September of2013, ~~the~~Venoco ~~Company's~~paid ~~subsidiaries~~a ~~other~~cash ~~than~~dividend ~~Ellwood Pipeline,~~of $15.8 ~~Inc~~million to DPC.

~~As noted~~ Venoco ~~above~~8.875% Senior Notes. In February 2011, ~~the~~Venoco ~~Company~~issued ~~repaid~~$500 million ain ~~portion~~8.875% ofsenior ~~amounts~~notes ~~outstanding~~due ~~under~~in ~~the~~February ~~second~~2019 ~~lien~~at ~~term~~par. ~~loan~~The notes ~~facility~~pay interest semi-annually in ~~the~~arrears ~~first~~on ~~quarter~~February 15 and August 15 of ~~2013~~each ~~with~~year. ~~proceeds~~Venoco ~~from~~may redeem the ~~Sacramento~~notes ~~Basin~~prior ~~asset sale.~~to ~~The~~February 15, ~~current~~2015 ~~portion~~at ofa ~~long-term~~"make ~~debt~~whole ofpremium" ~~$104~~defined in the indenture.~~5 million~~ atBeginning ~~December~~February 3115, ~~2012~~2015, ~~reflects~~Venoco may redeem the ~~principal~~notes ~~amounts~~at ~~that~~a redemption price of 104.438% of the ~~Company~~principal ~~was~~amount ~~required~~and declining to ~~repay~~100% onby ~~the~~February 15, ~~facility~~2017. ~~from~~The ~~the~~notes ~~sale~~are ~~proceeds~~senior ~~that~~unsecured ~~the~~obligations ~~Company~~and ~~received~~contain onoperational ~~December 31~~covenants that, ~~2012~~among ~~and~~other ~~January 2~~things, ~~2013~~limit Venoco's ability to make investments, ~~less~~incur ~~the~~additional ~~portion~~indebtedness, ~~that~~issue ~~the~~preferred ~~Company~~stock, ~~repaid~~pay dividends, ~~with~~repurchase ~~additional~~its ~~borrowings~~stock, oncreate ~~the~~liens ~~revolving~~or ~~credit~~sell ~~facility~~assets.

8DPC 12.~~875~~25% / 13.00% Senior PIK Toggle Notes. In ~~February~~August ~~2011~~2013, ~~the~~DPC ~~Company~~ issued $~~500~~255 million inprincipal 8amount of 12.~~875~~25% / 13.00% senior PIK toggle notes due in2018 ~~February~~at ~~2019~~97.304% atof par. ~~Concurrently~~ ~~with~~ Interest on the ~~sale~~notes is payable on February 15 and August 15 of ~~the~~each 8year, commencing February 15, 2014.~~875%~~ ~~senior~~The initial interest payment on the notes will be payable in cash. DPC is a holding company that owns no material assets other than stock of Venoco; accordingly, it will be able to pay cash interest on its notes only to the ~~Company~~extent ~~repaid~~that it receives cash dividends or distributions from Venoco. For each interest period after the initial interest period (other than for the final interest period ending at the stated maturity, which will be paid in ~~full~~cash), DPC will, in certain circumstances, be permitted to pay interest on the ~~outstanding~~notes by increasing the principal ~~balance~~amount of ~~$455~~the notes or issuing new notes (collectively, "PIK interest").~~3 million~~ Cash interest on ~~its~~the ~~then~~notes ~~outstanding~~will ~~second~~accrue ~~lien~~at ~~term~~the ~~loan.~~rate ~~The~~of 812.~~875~~25% ~~senior~~per ~~notes~~annum. ~~pay~~ PIK interest ~~semi-annually~~on inthe ~~arrears~~notes onwill ~~February 15~~accrue ~~and~~at ~~August 15~~the rate of ~~each~~13.00% ~~year~~per annum until the next payment of cash interest. The ~~Company~~notes are not currently guaranteed by any of DPC's subsidiaries. DPC may redeem the notes, in whole or in part, at any time prior to ~~February~~August 15, 2015, at a "make -whole ~~premium~~" ~~defined~~redemption price described in the indenture. ~~Beginning~~DPC ~~February 15,~~may also ~~2015,~~redeem ~~the~~all ~~Company~~or ~~may~~any ~~redeem~~part of the notes on and after August 15, 2015 at a redemption price of ~~104~~106.~~438~~125% of the principal amount and declining to 100% by ~~February~~August 15, 2017. The ~~8.875% senior~~ notes are senior unsecured obligations and contain operational covenants that, among other things, limit ~~the~~our ~~Company's~~ ability to make investments, incur additional indebtedness, issue preferred stock, pay dividends, repurchase ~~its~~ stock, create liens or sell assets.

~~11.50%~~ The following ~~Senior~~summarizes ~~Notes. In October 2009,~~ the ~~Company~~terms ~~issued $150.0 million~~ of ~~11.50%~~the ~~senior~~agreements ~~notes~~governing ~~due~~the ~~October~~Company's ~~2017~~debt atthat a(i) was ~~price~~outstanding ~~of 95.03%~~as of ~~par. The~~December 31, ~~senior~~2012 ~~notes~~but ~~pay interest semi-annually in arrears on April~~(ii) 1all ~~and~~or ~~October 1~~substantially all of ~~each~~which ~~year.~~had ~~The~~been ~~Company~~repaid ~~may~~as ~~redeem~~of ~~the senior notes prior to October~~September 130, 2013.

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3. LONG-TERM DEBT (Continued)

~~2013 at~~ Venoco Second Lien Term Loan Facility. Venoco entered into a ~~"make-whole~~$315.0 million ~~price"~~senior ~~defined~~secured second lien term loan facility in October 2012 (the "second ~~indenture.~~lien ~~Beginning~~term ~~October 1,~~loan ~~2013~~facility"), ~~the~~which ~~Company~~was ~~may~~issued ~~redeem~~at 98% of the ~~notes~~principal atamount aof ~~redemption~~the ~~price~~facility. ~~equal~~Venoco torepaid ~~105~~$214.~~75%~~7 million of the outstanding principal amount ~~and~~under ~~declining~~the facility, and to$6.4 million ~~100%~~in byprepayment ~~October 1~~penalties, ~~2016.~~in ~~The~~the 11first quarter of 2013 with proceeds from the Sacramento Basin asset sale.~~50%~~ ~~notes~~In ~~are~~March ~~senior~~2013, ~~unsecured~~it ~~obligations~~used $107 million of additional borrowings under the revolving credit facility to repay all remaining amounts outstanding under the facility and ~~contain~~$3.0 million ~~covenants~~in ~~that,~~prepayment ~~among~~penalties. ~~other~~Loans ~~things~~made under the second lien term loan facility were designated, ~~limit~~at the Company's ~~ability~~option, toas ~~make~~either ~~investments,~~"Base ~~incur~~Rate ~~additional~~Loans" or "LIBO Rate Loans." Loans designated as Base Rate Loans bore interest at a floating rate equal to (i) the greater of ~~debt,~~(x) the ~~issue~~administrative ~~preferred~~agent's ~~stock~~announced prime rate, ~~pay~~(y) the ~~dividends~~federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.0%, ~~repurchase~~plus ~~its~~(ii) 6.00%. ~~stock~~Loans designated as LIBO Rate Loans bore interest at LIBOR plus 7.00%. Per the second lien term loan agreement, ~~create~~LIBOR ~~liens~~was orto ~~sell~~be ~~assets~~not less than 1.50%.

The ~~Company~~agreement governing the second lien term loan facility contained customary representations, warranties, events of default, covenants and indemnities. The facility was insecured ~~compliance~~by second ~~with~~priority liens on substantially all ~~debt~~of ~~covenants~~the atCompany's ~~June 30~~oil and natural gas properties and other assets, ~~2013~~including the equity interests in all of Venoco's subsidiaries, and was unconditionally guaranteed by each of Venoco's subsidiaries other than Ellwood Pipeline, Inc.

As noted above, Venoco 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 Venoco was required to repay on the facility from the sale proceeds that Venoco received on December 31, 2012 and January 2, 2013, less the portion that Venoco repaid with additional borrowings on the revolving credit facility.

Venoco 11.50% Senior Notes. In October 2009, Venoco issued $150 million of 11.50% senior notes due October 2017 at a price of 95.03% of par. The notes paid interest semi-annually in arrears on April 1 and October 1 of each year. The 11.50% notes were senior unsecured obligations and contained covenants that, among other things, limited Venoco's ability to make investments, incur additional debt, issue preferred stock, pay dividends, repurchase its stock, create liens or sell assets.

In August 2013, Venoco commenced a tender offer to purchase for cash any and all of the $150 million outstanding principal amount of the 11.50% senior notes. In connection with the tender offer, Venoco also solicited consents from the holders of the notes to the amendment of the indenture governing those notes to eliminate substantially all of the restrictive covenants in the indenture, among other changes. Holders of approximately 99% of the principal amount of the notes tendered their notes and provided the related consents. Venoco redeemed the remaining notes in October 2013 pursuant to the terms of the indenture. The aggregate cost to Venoco of purchasing the notes in the tender offer, making the related consent payments and redeeming the remaining notes was approximately $160 million. Venoco funded the majority of this amount with a capital contribution from DPC of approximately $158 million. DPC funded the capital contribution with a portion of the proceeds of the offering of its 12.25% / 13.00% senior PIK toggle notes.

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3. LONG-TERM DEBT (Continued)

DPC Secured Notes. In October 2012, DPC incurred $60 million of indebtedness in the form of notes issued in a private placement pursuant to a note purchase agreement. DPC's obligations under the notes were secured by substantially all of its assets, which consisted principally of all of the common stock of Venoco.

Interest on the notes was payable in cash, in additional notes or in a combination of additional notes and cash. If paid entirely in cash, the interest rate was 18% per annum; if paid entirely in kind, the interest rate was 33% per annum. If paid in a combination of cash and additional notes, the interest rate varied between those amounts based on the proportion of cash paid.

The notes were due to mature on October 5, 2015. Pursuant to the terms of the notes, DPC redeemed the notes in August 2013 with proceeds of the issuance of its 12.25% / 13.00% senior PIK toggle notes. The aggregate cost of redeeming the notes was approximately $16.7 million.

The Company was in compliance with all debt covenants at September 30, 2013.

4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Derivative Agreements. The Company utilizes swap and collar agreements and option contracts to hedge the effect of price changes on a portion of its future oil 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~~Venoco's revolving credit facility. Collateral under the revolving credit facility supports ~~the Company~~Venoco'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~~Venoco'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~~September 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.~~

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paid was $9.5 million, of which $1.0 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):

	Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2013			2012			2013
Realized commodity derivative losses (gains)	$	(67,~~786~~597	)	$	54,~~132~~261		$	(4740,~~882~~285	)	$	1924,~~749~~010
Amortization of commodity derivative premiums		21,~~224~~203			1,~~018~~017			1011,~~019~~222			12,~~967~~984
Unrealized commodity derivative losses (gains) for changes in fair value		(240,~~134~~289	)		~~(26~~8,~~101~~893	)		61101,~~705~~994			(3829,~~324~~431	)
Commodity derivative losses (gains), net	$	(649,~~696~~089	)	$	~~(19~~14,~~951~~171	)	$	2372,~~842~~931		$	(162,~~608~~437	)

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~~nine months of 2013. During the ~~second~~first ~~quarter~~nine months 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~~September 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~~ 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").

	Oil (Brent)
	Barrels/day		Weighted Avg. Prices per Bbl
July 1 - December 31, 2013:
October 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
Swaps		1,000	$	106.00
Collars		4,100		$90.00/$98.59
Puts		575	$	90.00
January 1 - December 31, 2015:
Collars		3,675	$	90.00/$98.95

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 14

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~~indexes~~ 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~~September 30, 2013 and December 31, 2012 are summarized below. The net fair value of the Company's derivatives changed by $3727.89 million from a net liability of $40.7 million at December 31, 2012 to a net liability of $212.98 million at ~~June~~September 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~~September 30, 2013
Current Assets—Commodity derivatives:
Oil derivative contracts	$	153		$	21,~~128~~346
Other Assets—Commodity derivatives:
Oil derivative contracts		—			~~478~~445
Current Liabilities—Commodity derivatives:
Oil derivative contracts		(19,817	)		(27,~~359~~002	)
Gas derivative contracts		(790	)		—
		(20,607	)		(27,~~359~~002	)
Commodity derivatives:
Oil derivative contracts		(17,482	)		(37,~~137~~589	)
Gas derivative contracts		(2,805	)		—
		(20,287	)		(37,~~137~~589	)
Net derivative asset (liability)	$	(40,741	)	$	(212,~~890~~800	)

5. ASSET RETIREMENT OBLIGATIONS

The Company's asset retirement obligations represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut-in properties (including removal of certain onshore and offshore facilities) at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its asset retirement obligations 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

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5. ASSET RETIREMENT OBLIGATIONS (Continued)

~~estimates~~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~~nine months ended ~~June~~September 30, 2012 and 2013 (in thousands):

	Six Months Ended June 30,
	Nine Months Ended September 30,
	2012			2013
Asset retirement obligations at beginning of period	$	92,508		$	43,319
Revisions of estimated liabilities		(2559	)		(~~332~~360	)
Liabilities incurred or acquired		~~904~~1,060			~~119~~233
Liabilities settled or disposed		(3,~~160~~664	)		(7,551	)
Accretion expense		24,~~841~~298			1,~~271~~866
Asset retirement obligations at end of period		9394,~~068~~143			3637,~~826~~507
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)		(~~500~~1,000	)		(2,200	)
Long-term asset retirement obligations	$	9293,~~568~~143		$	3435,~~626~~307

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~~nine months of 2013 primarily relate to the Sacramento Basin asset sale.

6. CAPITAL STOCK

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~~Venoco ~~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~~ 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.

14 During the third quarter, DPC issued 214,555 shares to its Employee Stock Ownership Plan ("ESOP"). As of September 30, 2013, there were 30,150,933 shares of common stock of DPC and 29,936,378 shares of common stock of Venoco outstanding.

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(UNAUDITED)

7. SHARE-BASED PAYMENTS

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:

•: All unvested restricted share awards were converted into rights-to-receive awards (RTR) at $12.50 per share, subject to original service conditions. The original restricted share grants generally vested over a four year period, with 25% vesting on each subsequent anniversary of the grant date. This conversion is considered a modification of the original grant date terms and compensation expense is being recognized over the requisite service period for the greater of the original grant date fair value or $12.50 per share.
•: All previously granted stock option awards, which had a maximum life of ten years, were fully vested at December 31, 2011. Holders of in-the-money options were paid the difference between $12.50 per share and the original exercise price and replacement share appreciation rights (SARs) were granted to these holders with an exercise price of $12.50 per share. Holders of options with an original exercise price greater than $12.50 were cancelled and replacement SARs were granted at the original exercise price. These SAR awards are 100% vested on the grant date and retain the original option award termination date.

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

•: Restricted share unit awards (RSUs) that generally vest over a four year service period beginning April 1, 2013. At each vesting date, holders of the RSUs are paid the fair value of DPC common stock. The estimated fair value of the award is recognized as expense over the requisite service period and fair values are remeasured for unvested awards at each reporting date until the date of settlement. Certain grants of RSUs to officers and directors vest based on achievement of performance measurements used to determine the Company's annual cash bonus payout and related expense is recognized using graded vesting resulting in more accelerated expense recognition than expense recognized using straight line vesting over the service period.
•: SAR awards with an exercise price of $12.50 per share for each unvested RTR award, subject to the original service conditions of the RTR. Compensation expense is recognized based on the grant date fair values over the remaining requisite service period of the RTR and these awards have a ten year life from the date of grant.
•: SAR awards for each Venoco common share held at the date of the going private transaction (except for the Company's Executive Chairman) with an exercise price of $12.50 per unit. All such SAR awards are 100% vested on the grant date and have a ten year life from the date of grant.

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~~

1517

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7. SHARE-BASED PAYMENTS (Continued)

~~contribution~~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~~nine months ended ~~June~~September 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~~189,300		$	8.33		1,478,507		$	62.5269	214,552		$	8.33
Vested or exercised	(~~774~~777,~~693~~130	)	$	12.50	(241,419	)	$	—8.33		—		$	—	—		$	—
Cancelled and other	(8189,~~845~~789	)	$	12.50	(~~138~~150,~~014~~997	)	$	8.33		(~~374~~417,~~744~~759	)	$	3.5169	(914,~~395~~758	)	$	8.33
Outstanding, end of period	1,~~265~~254,~~299~~918				~~799~~788,~~282~~299					4,~~414~~371,~~683~~668				~~205~~199,~~157~~794
Exercisable, end of period										~~805~~762,~~641~~626
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:~~ 18

		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

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7. SHARE-BASED PAYMENTS (Continued)

~~based~~ The onfollowing ~~the~~assumptions ~~historical~~were ~~volatility~~used ~~of public companies with characteristics similar~~ to compute the ~~Company~~grant ~~for~~date ~~the~~fair ~~past~~value ~~seven~~of ~~years.~~SARs at:

	December 31, 2012	September 30, 2013

Expected lives	1.0 - 6.5 years	1.0 - 7.0 years
Risk free interest rates	0.16% - 1.07%	0.10% - 2.02%
Estimated volatilities	45% - 60%	45% - 60%
Dividend yield	0.0%	0.0%

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

	June 30, 2013
	December 31, 2012						September 30, 2013
	Current Liability		Long Term Liability		Total Liability		Current Liability		Long Term Liability		Total Liability
Rights to receive	$	139,~~210~~719	$	—8,055	$	1317,~~210~~774	$	14,501	$	—	$	14,501
Restricted share units		~~1,682~~705		~~1,345~~—		~~3,027~~705		622		1,344		1,966
Share appreciation rights		~~413~~—		62,~~708~~386		72,~~121~~386		—		3,702		3,702
ESOP		—		~~245~~—		~~245~~—		—		193		193
Total share-based compensation liability	$	1510,~~305~~424	$	810,~~298~~441	$	2320,~~603~~865	$	15,123	$	5,239	$	20,362

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):~~ 19

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2013			2012			2013
General and administrative expense	$	1,840		$	4,940		$	4,060		$	12,585
Oil and natural gas production expense		190			549			510			1,183
Total share-based compensation costs		2,030			5,489			4,570			13,768
Less: share-based compensation costs capitalized		(822	)		(1,141	)		(1,822	)		(2,971	)
Share-based compensation expense, net	$	1,208		$	4,348		$	2,748		$	10,797

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.

8. FAIR VALUE MEASUREMENTS

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87. ~~FAIR~~SHARE-BASED ~~VALUE~~PAYMENTS ~~MEASUREMENTS~~ (Continued)

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~~recognized ~~fair~~total ~~value balances~~ share-based oncompensation ~~the~~costs ~~observability~~as offollows ~~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~~thousands): ~~and the lowest priority to unobservable inputs (level 3 measurement).~~

	Three Months Ended September 30,						Nine Months Ended September 30,

	2012			2013			2012			2013
General and administrative expense	$	1,790		$	(2,890	)	$	5,850		$	9,695
Oil and natural gas production expense		160			(321	)		670			862

Total share-based compensation costs		1,950			(3,211	)		6,520			10,557
Less: share-based compensation costs capitalized		(453	)		708			(2,275	)		(2,263	)

Share-based compensation expense, net	$	1,497		$	(2,503	)	$	4,245		$	8,294

As of September 30, 2013, there was $15.8 million of total unrecognized compensation cost, which is expected to be recognized over a period of 3.25 years.

8. FAIR VALUE MEASUREMENTS

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

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

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

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

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

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value 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).~~

	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	)

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.

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8. FAIR VALUE MEASUREMENTS (Continued)

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

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

Assets (Liabilities):
Commodity derivative contracts	$	—	$	1,791		$	—		$	1,791
Commodity derivative contracts		—		(14,591	)		—			(14,591	)
Share-based compensation		—		—			(5,861	)		(5,861	)

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~~shares, 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):~~ 21

	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	)

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8. FAIR VALUE MEASUREMENTS (Continued)

~~Fair Value of Financial Instruments. The Company's financial instruments consist primarily of cash and cash equivalents, accounts~~value ~~receivable and payable~~estimate, ~~derivatives~~it ~~(discussed~~is 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 Companymanagement's ~~revolving~~opinion ~~credit~~that ~~facility~~the ~~approximated~~valuations ~~fair~~afforded ~~value~~by ~~because~~existing ~~the~~models ~~interest~~are ~~rate~~different offrom the ~~facility is variable. The fair~~ value ofthat the ~~second~~shares ~~lien~~would ~~term~~realize ~~loan facility~~if ~~and~~traded ~~the senior notes listed~~ in the ~~tables below were derived from available~~ market ~~data~~. ~~This disclosure does not impact our financial position, results of operations or cash flows (in thousands).~~

	December 31, 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

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

	Nine Months Ended September 30,

	2012		2013
Fair value liability, beginning of period	$	—	$	(3,091	)
Transfers into Level 3(1)		—		(10,296	)
Transfers out of Level 3(2)		—		3,367
Change in fair value of Level 3		—		4,159

Fair value liability, end of period	$	—	$	(5,861	)

(1): The transfers into Level 3 liability during the first nine months of 2013 relate to RSU, SAR and ESOP grants made by the Company to officers, directors and certain employees, and requisite service period expense.
(2): The transfers out of Level 3 liability during the first nine months of 2013 relate to cash settlements of RSU grants, and forfeitures of RSU, SAR and ESOP grants as a result of employee terminations.

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 Venoco'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, senior notes, secured notes and senior PIK toggle notes listed in the tables below were derived from available market data. This disclosure does not impact our financial position, results of operations or cash flows (in thousands).

	December 31, 2012				September 30, 2013

	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Venoco:
Revolving credit agreement	$	—	$	—	$	208,000	$	208,000
Second lien term loan		308,960		322,088		—		—
11.50% senior notes		144,724		155,625		521		551
8.875% senior notes		500,000		468,625		500,000		508,000
Denver Parent Corporation:
Secured notes		60,000		60,000		—		—
12.25% / 13.00% senior PIK toggle notes		—		—		248,249		253,725

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9. CONTINGENCIES

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~~2005 (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~~it ~~defendants~~were ~~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.

20 In August 2013 Venoco and the SLC entered into a definitive settlement agreement pursuant to which (i) the SLC agreed with the Company's methodology for calculating royalties on oil and gas production from the South Ellwood field and (ii) the parties agreed that all royalty payments made through February 2013 were correct. The litigation between the parties has been dismissed with prejudice without liability to the Company.

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, three lawsuits were filed in the Delaware Court of Chancery in September 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, five additional suits were filed in Delaware (three in January and two in February) and three suits were

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9. CONTINGENCIES (Continued)

~~transporting~~filed ~~oil~~in ~~from~~federal ~~the~~court ~~South~~in ~~Ellwood~~Colorado ~~field~~(two toin ~~the~~January ~~point~~and ofone ~~sale~~ in ~~calculating~~February) ~~the~~naming ~~market~~as ~~price~~defendants ~~of oil at~~ the ~~wellhead~~Company ~~for~~and ~~purposes~~each of ~~calculating~~ its ~~royalty obligation~~directors. ~~With~~In ~~respect~~March to2013 the ~~oil price,~~plaintiffs ~~the~~in ~~Company~~Delaware ~~has~~filed ~~paid~~a ~~royalties~~consolidated amended ~~based~~class onaction ~~the~~complaint ~~price the Company actually received~~ in ~~arms-length~~which ~~transactions.~~they ~~The~~requested ~~SLC contends~~ that the ~~Company~~court ~~should~~determine beamong ~~paying~~other ~~royalties~~things ~~based~~that on (i) the ~~higher~~merger ~~of the~~consideration ~~price~~is ~~actually~~inadequate ~~received~~ and the ~~highest~~Merger ~~"posted~~Agreement ~~price"~~was ~~for~~entered ~~oil~~into ~~sold~~ in breach of the ~~Midway~~fiduciary ~~Sunset~~duties ~~field,~~of ~~near~~the ~~Bakersfield,~~defendants ~~California.~~and ~~With~~is ~~respect~~therefore tounlawful ~~transportation~~and ~~costs,~~unenforceable and (ii) the ~~Company~~merger ~~believes~~should ~~that~~be ~~state law~~rescinded ~~allows~~or in the ~~Company~~alternative, tothe ~~consider~~class ~~the~~should ~~cost~~be ofawarded ~~delivering~~damages to ~~the~~compensate ~~oil~~them ~~from~~for the ~~field~~loss toas ~~the~~a ~~point~~result of ~~sale in determining~~ the ~~market~~breach ~~price~~ of ~~the~~fiduciary ~~oil~~duties atby the ~~wellhead~~defendants. InThe ~~February~~Colorado ~~2012~~actions ~~the~~have ~~Company~~been ~~filed~~administratively ~~a cross-complaint~~closed ~~against~~pending ~~the~~resolution ~~SLC~~of ~~alleging~~the ~~that~~Delaware ~~the~~case. The Company ~~had~~has ~~overpaid~~reviewed ~~royalties~~the onallegations ~~oil~~contained ~~and~~in ~~gas~~the ~~produced~~amended ~~from~~complaint ~~the~~and ~~South~~believes ~~Ellwood~~they ~~field~~are bywithout ~~approximately $4~~merit.~~3 million.~~ ~~Most~~Trial ofin ~~the~~this ~~overpayment~~matter is ~~attributable~~ toexpected ~~the failure by the Company~~ to ~~adjust~~occur ~~its~~in ~~sales~~late ~~price to include all transportation costs associated with marketing its crude oil~~2014.

~~The Company~~ Denbury isArbitration—In inJanuary ~~discussions~~2013 ~~with~~ the ~~SLC~~Company toand ~~settle~~its ~~the~~wholly ~~matter.~~owned ~~The~~subsidiary, ~~proposed~~TexCal ~~settlement~~Energy ~~would~~South Texas, L.P. (i"TexCal"), ~~affirm~~notified Denbury Resources, Inc. ("Denbury") through its subsidiary Denbury Onshore, LLC that it was invoking the ~~Company's~~arbitration ~~methodology~~provisions ~~for~~contained ~~computing~~in ~~royalties~~contracts onbetween ~~production~~TexCal ~~from~~and ~~the~~Denbury pursuant to ~~South~~which ~~Ellwood~~TexCal ~~field~~conveyed ~~based~~its oninterest ~~actual~~in ~~sales~~the ~~prices~~Hastings isComplex ~~correct~~to Denbury and ~~(ii)~~retained ~~settle~~a ~~all~~reversionary ~~claims~~interest. byDenbury is obligated to convey the ~~SLC~~reversionary ~~for~~interest ~~royalty~~to ~~under~~TexCal ~~payments~~at ~~and~~"payout," ~~claims~~as bydefined in the ~~Company~~contracts. ~~for~~The ~~royalty~~dispute ~~over~~involves ~~payments~~the ~~through~~calculation ~~February~~of ~~2013~~the cost of CO2 delivered to the Hastings Complex which is used in Denbury's enhanced oil recovery operations. The Company ~~Under~~believes that Denbury has materially overcharged the ~~proposed~~payout ~~settlement~~account ~~neither~~for ~~party~~the ~~would~~cost ~~pay~~of CO2 and the ~~other~~cost ~~party~~of transporting it to the Hastings Complex. AThe ~~settlement~~arbitration ~~agreement~~hearing ~~has~~was ~~not~~completed ~~been~~in August ~~signed~~2013. ItA decision by the arbitration panel is ~~possible~~expected ~~that~~in late 2013. An adverse determination in the ~~final~~arbitration ~~terms~~proceeding could ~~vary~~reduce orthe ~~that~~amount aof ~~final~~proved ~~settlement~~reserves isfrom ~~not~~this reversionary ~~reached~~interest and delay the timing for cash flows from those reserves.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

9. CONTINGENCIES (Continued)

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.

10. GUARANTOR FINANCIAL INFORMATION

All subsidiaries of the Company other than Ellwood Pipeline Inc. ("Guarantors") have fully and unconditionally guaranteed, on a joint and several basis, ~~the Company~~Venoco's obligations ~~under~~ under its 118.50875% senior notes (and, 8until October 2013, under its 11.~~875~~50% 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~~September 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. There are currently no guarantors of DPC's 12.25%/13.00% senior PIK toggle notes.

2224

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING ~~STATEMENTS~~BALANCE ~~OF OPERATIONS~~SHEETS ~~THREE~~AT ~~MONTHS~~SEPTEMBER ~~ENDED JUNE~~ 30, 2013 (Unaudited) (in thousands)

	Venoco, Inc.			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
REVENUES:
ASSETS
Oil and natural gas sales	$	81,158		$	291		$	—		$	—		$	81,449
CURRENT ASSETS:
Other		315			—			3,497			(2,902	)		910
Cash and cash equivalents	$	16		$	—		$	—		$	—		$	16
Total revenues		81,473			291			3,497			(2,902	)		82,359
Accounts receivable		25,081			97			993			—			26,171
EXPENSES:
Inventories		5,380			—			—			—			5,380
Lease operating expense		17,369			15			530			—			17,914
Prepaid expenses and other current assets		5,322			—			—			—			5,322
Property and production taxes		1,364			15			28			—			1,407
Commodity derivatives		1,346			—			—			—			1,346
Transportation expense		2,852			3			—			(2,810	)		45
TOTAL CURRENT ASSETS		37,145			97			993			—			38,235
Depletion, depreciation and amortization		12,168			26			212			—			12,406
PROPERTY, PLANT & EQUIPMENT, NET		815,588			(184,229	)		19,290			—			650,649
Accretion of asset retirement obligations		575			30			10			—			615
COMMODITY DERIVATIVES		445			—			—			—			445
General and administrative, net of amounts capitalized		10,333			1			133			(92	)		10,375
INVESTMENTS IN AFFILIATES		555,255			—			—			(555,255	)		—
Total expenses		44,661			90			913			(2,902	)		42,762
OTHER		18,210			60			—			—			18,270
Income from operations		36,812			201			2,584			—			39,597
TOTAL ASSETS		1,426,643			(184,072	)		20,283			(555,255	)		707,599
FINANCING COSTS AND OTHER:
LIABILITIES AND STOCKHOLDERS' EQUITY
Interest expense, net		18,567			—			(1,166	)		—			17,401
CURRENT LIABILITIES:
Amortization of deferred loan costs		906			—			—			—			906
Accounts payable and accrued liabilities		41,494			—			—			—			41,494
Commodity derivative losses (gains), net		(19,951	)		—			—			—			(19,951	)
Interest payable		6,319			—			—			—			6,319
Total financing costs and other		(478	)		—			(1,166	)		—			(1,644	)
Commodity and interest derivatives		7,002			—			—			—			7,002
Equity in subsidiary income		2,448			—			—			(2,448	)		—
Share-based compensation		15,123			—			—			—			15,123
Income (loss) before income taxes		39,738			201			3,750			(2,448	)		41,241
TOTAL CURRENT LIABILITIES:		69,938			—			—			—			69,938
Income tax provision (benefit)		(1,503	)		78			1,425			—			—
LONG-TERM DEBT		708,521			—			—			—			708,521
Net income (loss)	$	41,241		$	123		$	2,325		$	(2,448	)	$	41,241
COMMODITY AND INTEREST DERIVATIVES		7,589			—			—			—			7,589
ASSET RETIREMENT OBLIGATIONS		33,073			1,495			739			—			35,307
SHARE-BASED COMPENSATION		5,239			—			—			—			5,239
INTERCOMPANY PAYABLES (RECEIVABLES)		721,242			(653,998	)		(67,280	)		36			—
TOTAL LIABILITIES		1,545,602			(652,503	)		(66,541	)		36			826,594
TOTAL STOCKHOLDERS' EQUITY		(118,959	)		468,431			86,824			(555,291	)		(118,995	)
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,426,643		$	(184,072	)	$	20,283		$	(555,255	)	$	707,599

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VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

	Venoco, Inc.			Guarantor Subsidiaries		Non-Guarantor Subsidiary			Eliminations			Consolidated
REVENUES:
Oil and natural gas sales	$	~~163~~95,~~600~~032		$	~~724~~345	$	—		$	—		$	~~164~~95,~~324~~377
Other		~~2,677~~714			18—		54,~~001~~121			(43,~~158~~514	)		31,~~538~~321
Total revenues		~~166~~95,~~277~~746			~~742~~345		54,~~001~~121			(43,~~158~~514	)		~~167~~96,~~862~~698
EXPENSES:
Lease operating expense		43,671			27		845			—			44,543
Lease operating expenses		22,376			8		515			—			22,899
Property and production taxes		61,~~884~~460			1—		32211			—			61,~~917~~671
Transportation expense		83,~~652~~905			—4		—			(3,~~983~~427	)		~~4,669~~482
Depletion, depreciation and amortization		4322,~~066~~005			5226		~~349~~209			—			4322,~~467~~240
Accretion of asset retirement obligations		21,~~758~~419			6428		1910			—			21,~~841~~457
General and administrative, net of amounts capitalized		2211,~~158~~793			1—		~~246~~116			(~~175~~87	)		2211,~~230~~822
Total expenses		~~127~~62,~~189~~958			~~145~~66		1,~~491~~061			(43,~~158~~514	)		~~124~~60,~~667~~571
Income (loss) from operations		3932,~~088~~788			~~597~~279		3,~~510~~060			—			4336,~~195~~127
FINANCING COSTS AND OTHER:
Interest expense, net		3317,~~477~~488			—		(~~1,886~~990	)		—			3116,~~591~~498
Amortization of deferred loan costs		~~1,154~~597			—		—			—			~~1,154~~597
Commodity derivative losses (gains), net		2349,~~842~~089			—		—			—			2349,~~842~~089
Total financing costs and other		5867,~~473~~174			—		(~~1,886~~990	)		—			5666,~~587~~184
Equity in subsidiary income		32,~~716~~685			—		—			(32,~~716~~685	)		—
Income (loss) before income taxes		(1531,~~669~~701	)		~~597~~279		54,~~396~~050			(32,~~716~~685	)		(1330,~~392~~057	)
Income tax provision (benefit)		(21,~~277~~646	)		~~227~~106		21,~~050~~540			—			—
Net income (loss)	$	(1330,~~392~~055	)	$	~~370~~173	$	32,~~346~~510		$	(32,~~716~~685	)	$	(1330,~~392~~057	)

Table of Contents

VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

	Venoco, Inc.			Guarantor Subsidiaries		Non-Guarantor Subsidiary			Eliminations			Consolidated
REVENUES:
Oil and natural gas sales	$	~~166~~79,~~807~~388		$	~~601~~308	$	—		$	—		$	~~167~~79,~~408~~696
Other		~~1,024~~117			—		6,~~768~~320			(5,~~578~~188	)		21,~~214~~249
Total revenues		~~167~~79,~~831~~505			~~601~~308		6,~~768~~320			(5,~~578~~188	)		~~169~~80,~~622~~945
EXPENSES:
Lease operating expense		3517,~~256~~477			2719		~~1,162~~778			—			3618,~~445~~274
Property and production taxes		2,491			15		28			—			2,534
Production and property taxes		(626	)		1		153			—			(472	)
Transportation expense		5,~~470~~142			63		—			(5,~~393~~095	)		8350
Depletion, depreciation and amortization		2312,~~507~~355			5226		~~419~~170			—			2312,~~978~~551
Accretion of asset retirement obligations		~~1,193~~556			5829		2010			—			~~1,271~~595
General and administrative, net of amounts capitalized		255,~~264~~326			1—		~~270~~125			(~~185~~93	)		255,~~350~~358
Total expenses		9340,~~181~~230			~~159~~78		1,~~899~~236			(5,~~578~~188	)		8936,~~661~~356
Income from operations		74,650			442		4,869			—			79,961
Income (loss) from operations		39,275			230		5,084			—			44,589
FINANCING COSTS AND OTHER:
Interest expense, net		3816,~~549~~869			—		(21,~~294~~195	)		—			3615,~~255~~674
Amortization of deferred loan costs		~~2,019~~868			—		—			—			~~2,019~~868
Loss on extinguishment of debt		2116,~~297~~787			—		—			—			2116,~~297~~787
Commodity derivative losses (gains), net		~~(16~~14,~~608~~171	)		—		—			—			~~(16~~14,~~608~~171	)
Total financing costs and other		4548,~~257~~695			—		(21,~~294~~195	)		—			4247,~~963~~500
Equity in subsidiary income		4,~~715~~036			—		—			(4,~~715~~036	)		—
Income (loss) before income taxes		34(5,~~108~~384	)		~~442~~230		76,~~163~~279			(4,~~715~~036	)		36(2,~~998~~911	)
Income tax provision (benefit)		(2,~~890~~473	)		~~168~~87		2,~~722~~386			—			—
Net income (loss)	$	36(2,~~998~~911	)	$	~~274~~143	$	43,~~441~~893		$	(4,~~715~~036	)	$	36(2,~~998~~911	)

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VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

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

REVENUES:
Oil and natural gas sales	$	258,632		$	1,069	$	—		$	—		$	259,701
Other		3,391			18		9,122			(7,672	)		4,859

Total revenues		262,023			1,087		9,122			(7,672	)		264,560
EXPENSES:
Lease operating expense		66,047			35		1,360			—			67,442
Property and production taxes		8,344			1		243			—			8,588
Transportation expense		12,557			4		—			(7,410	)		5,151
Depletion, depreciation and amortization		65,071			78		558			—			65,707
Accretion of asset retirement obligations		4,177			92		29			—			4,298
General and administrative, net of amounts capitalized		33,951			1		362			(262	)		34,052

Total expenses		190,147			211		2,552			(7,672	)		185,238

Income (loss) from operations		71,876			876		6,570			—			79,322
FINANCING COSTS AND OTHER:
Interest expense, net		50,965			—		(2,876	)		—			48,089
Amortization of deferred loan costs		1,751			—		—			—			1,751
Commodity derivative losses (gains), net		72,931			—		—			—			72,931

Total financing costs and other		125,647			—		(2,876	)		—			122,771

Equity in subsidiary income		6,401			—		—			(6,401	)		—

Income (loss) before income taxes		(47,370	)		876		9,446			(6,401	)		(43,449	)
Income tax provision (benefit)		(3,923	)		333		3,590			—			—

Net income (loss)	$	(43,447	)	$	543	$	5,856		$	(6,401	)	$	(43,449	)

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VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2013 (Unaudited)
(in thousands)

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

REVENUES:
Oil and natural gas sales	$	246,195		$	909	$	—		$	—		$	247,104
Other		1,141			—		13,088			(10,766	)		3,463

Total revenues		247,336			909		13,088			(10,766	)		250,567

EXPENSES:
Lease operating expense		52,733			46		1,940			—			54,719
Property and production taxes		1,865			16		181			—			2,062
Transportation expense		10,612			9		—			(10,488	)		133
Depletion, depreciation and amortization		35,862			78		589			—			36,529
Accretion of asset retirement obligations		1,749			87		30			—			1,866
General and administrative, net of amounts capitalized		30,590			1		395			(278	)		30,708

Total expenses		133,411			237		3,135			(10,766	)		126,017

Income (loss) from operations		113,925			672		9,953			—			124,550
FINANCING COSTS AND OTHER:
Interest expense, net		55,418			—		(3,489	)		—			51,929
Amortization of deferred loan costs		2,887			—		—			—			2,887
Loss on extinguishment of debt		38,084			—		—			—			38,084
Commodity derivative losses (gains), net		(2,437	)		—		—			—			(2,437	)

Total financing costs and other		93,952			—		(3,489	)		—			90,463

Equity in subsidiary income		8,751			—		—			(8,751	)		—

Income (loss) before income taxes		28,724			672		13,442			(8,751	)		34,087
Income tax provision (benefit)		(5,363	)		255		5,108			—			—

Net income (loss)	$	34,087		$	417	$	8,334		$	(8,751	)	$	34,087

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VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

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

	Venoco, Inc.			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations		Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	94124,~~096~~248		$	~~740~~1,065		$	59,~~095~~007		$	—	$	99134,~~931~~320
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties		(~~126~~170,~~136~~545	)		(3950	)		(56,~~864~~139	)		—		(~~132~~176,~~039~~734	)
Acquisitions of oil and natural gas properties		(~~235~~175	)		—			—			—		(~~235~~175	)
Expenditures for property and equipment and other		(12,~~211~~399	)		—			—			—		(12,~~211~~399	)
Proceeds from sale of oil and natural gas properties		23,~~368~~342			—			—			—		23,~~368~~342
Net cash provided by (used in) investing activities		(~~104~~149,~~214~~777	)		(3950	)		(56,~~864~~139	)		—		(~~110~~155,~~117~~966	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from (repayments of) intercompany borrowings		~~(68~~3,883	)		(~~701~~1,015	)		~~769~~(2,868	)		—		—
Proceeds from long-term debt		~~140~~200,000			—			—			—		~~140~~200,000
Principal payments on long-term debt		(~~138~~168,000	)		—			—			—		(~~138~~168,000	)
Payments for deferred loan costs		(93444	)		—			—			—		(93444	)
Proceeds from stock incentive plans and other		133			—			—			—		133
Net cash provided by (used in) financing activities		135,~~972~~572			(~~701~~1,015	)		~~769~~(2,868	)		—		231,~~040~~689
Net increase (decrease) in cash and cash equivalents		(810,~~146~~043	)		—			—			—		(810,~~146~~043	)
Cash and cash equivalents, beginning of period		8,165			—			—			—		8,165
Cash and cash equivalents, end of period	$	1918,208		$	—		$	—		$	—	$	1918,208

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VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

10. GUARANTOR FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE ~~SIX~~NINE MONTHS ENDED ~~JUNE~~SEPTEMBER 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	$	2947,~~529~~531		$	~~593~~877		$	913,~~373~~456		$	—	$	3961,~~495~~864
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties		(4578,~~563~~473	)		5			42(160	)		—		(4578,~~516~~628	)
Acquisitions of oil and natural gas properties		(40	)		—			—			—		(40	)
Acqusitions of oil and natural gas properties		(45	)		—			—			—		(45	)
Expenditures for property and equipment and other		(2,~~007~~243	)		—			—			—		(2,~~007~~243	)
Proceeds from sale of oil and natural gas properties		100,~~332~~305			—			—			—		100,~~332~~305
Net cash provided by (used in) investing activities		5219,~~722~~544			5			42(160	)		—		5219,~~769~~389
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from (repayments of) intercompany borrowings		10,013			(598	)		(9,415	)		—		—
Net proceeds from (repayments of) intercompany
Proceeds from long-term debt		294,900			—			—			—		294,900
borrowings		14,178			(882	)		(13,296	)		—		—
Principal payments on long-term debt		(426,900	)		—			—			—		(426,900	)
Proceeds from long-term debt		399,900			—			—			—		399,900
Premium paid to paydown debt		(1,107	)		—			—			—		(1,107	)
Principal payments on long-term debt		(656,379	)		—			—			—		(656,379	)
Payments for deferred loan costs		(91,~~450~~247	)		—			—			—		(91,~~450~~247	)
Premium to retire debt		(19,905	)		—			—			—		(19,905	)
Going private share repurchase costs		(9	)		—			—			—		(9	)
Net cash provided by (used in) financing activities		(132,553	)		(598	)		(9,415	)		—		(142,566	)
Dividend paid to Denver Parent Corporation		(15,800	)		—			—			—		(15,800	)
Net increase (decrease) in cash and cash equivalents		(50,302	)		—			—			—		(50,302	)
DPC capital contribution		158,385			—			—			—		158,385
Net cash provided by (used in) financing activities		(120,877	)		(882	)		(13,296	)		—		(135,055	)
Net increase (decrease) in cash and cash equivalents		(53,802	)		—			—			—		(53,802	)
Cash and cash equivalents, beginning of period		53,818			—			—			—		53,818
Cash and cash equivalents, end of period	$	~~3,516~~16		$	—		$	—		$	—	$	~~3,516~~16

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

~~The~~This ~~following~~Quarterly ~~discussion~~Report ~~and~~on ~~analysis~~Form 10-Q ~~should~~is bea ~~read~~combined inreport ~~conjunction~~being ~~with~~filed ~~"Management's~~by ~~Discussion~~Denver ~~and~~Parent ~~Analysis~~Corporation of("DPC") ~~Financial Condition~~ and ~~Results of Operations~~Venoco, Inc. ("Venoco"), ~~contained~~a indirect ~~our~~100% ~~Annual~~owned ~~Report~~subsidiary onof ~~Form 10-K~~DPC. ~~for~~DPC ~~the~~is ~~year~~a ~~ended~~holding ~~December 31,~~company ~~2012~~formed asto ~~well~~acquire asall ~~with~~of the ~~financial~~common ~~statements~~stock ~~and~~of ~~related~~Venoco ~~notes~~in ~~and~~a ~~the~~going ~~other information~~private ~~appearing~~transaction ~~elsewhere~~that was completed in ~~this~~October ~~report~~2012. Unless Asotherwise ~~used~~indicated inor ~~this~~the ~~report~~context otherwise requires, ~~unless~~(i) references ~~the~~to ~~context~~"DPC" ~~otherwise~~refer ~~indicates~~only to DPC, (ii) references to the "wecompany," "~~our~~we," "~~ours,~~our" and "us" refer, for periods following the going private transaction, to DPC and its subsidiaries, including Venoco and its subsidiaries, and for periods prior to the going private transaction, to Venoco and its subsidiaries and (iii) ~~Inc~~references to "Venoco" refer to Venoco and its subsidiaries. See "Explanatory Note" immediately preceding Part I of this report. Venoco and DPC are filing this combined report to satisfy reporting requirements under the indentures governing their respective senior notes. DPC recently filed a registration statement on Form S-4 to register the exchange of its ~~subsidiaries~~privately-issued ~~collectively~~12.25% / 13.00% senior PIK toggle notes due 2018 for substantially identical notes registered under the Securities Act of 1933.

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 Venoco's 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.

Overview

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. Our strategy is to grow through exploration, exploitation and development projects we believe to have the potential to add significant reserves on a cost-effective basis and through selective acquisitions of underdeveloped properties. In 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.

Recent Events

Going Private Transaction. In January 2012, weVenoco entered into a merger agreement with Timothy Marquez and certain of his affiliates, including DPC, pursuant to which an ~~affiliate~~DPC ofacquired ~~Mr. Marquez agreed to acquire~~ all of ~~our~~Venoco's common stock not beneficially owned by Mr. Marquez for $12.50 per share in cash. Wein ~~refer~~a ~~to this~~ transaction asthat ~~the~~was ~~going private~~completed ~~transaction. The going private transaction closed~~ in October 2012. ~~Following~~We ~~the~~refer ~~closing, Venoco's common stock is no longer publicly traded; however, we will continue reporting as a voluntary~~to ~~filer~~this ~~with~~transaction ~~the SEC~~ as ~~required by~~ the ~~indentures~~going ~~governing~~private ~~our senior notes~~transaction. In connection with the closing of the going private transaction, weVenoco entered into the fifth amended and restated credit agreement related to ~~our~~ its 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 anamendments ~~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." 33

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Amended Revolving Credit Agreement and Second Lien Repayment. In March 2013, Venoco entered into an amendment to its revolving credit agreement that increased the borrowing base under the facility to $270 million. Venoco 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 August 2013, Venoco entered into a further amendment to the revolving credit facility to increase its ability to pay dividends to DPC. The amendment generally permits Venoco, subject to certain conditions, to pay cash dividends to DPC up to a maximum amount of $35 million in a four-quarter period on a rolling basis.

DPC Notes Offering and Debt Tender Offer. In August 2013, DPC issued $255 million principal amount of 12.25% / 13.00% senior PIK toggle notes due 2018 at 97.304% of par. DPC used the proceeds of the offering to redeem its then outstanding senior secured notes for $83.2 million, including $16.7 million of redemption premium and $1.5 million of accrued interest, and to make a capital contribution to Venoco of approximately $158 million. Contemporaneously with the DPC notes offering, Venoco commenced a tender offer to purchase for cash any and all of the $150 million outstanding principal amount of its 11.50% senior notes due 2017. In connection with the tender offer, Venoco also solicited consents from the holders of the 11.50% senior notes to the amendment of the indenture governing those notes to eliminate substantially all of the restrictive covenants in the indenture, among other changes. Holders of approximately 99% of the principal amount of the notes tendered their notes and provided the related consents. Venoco then redeemed the remaining notes in October 2013 pursuant to the terms of the indenture. The aggregate cost to Venoco of purchasing the notes in the tender offer, making the related consent payments and redeeming the remaining notes was approximately $160.2 million. Venoco funded the majority of this amount with the capital contribution from DPC.

Master Limited Partnership. Venoco has submitted to the SEC a draft registration statement relating to a master limited partnership, or MLP, that would own a portion of its producing properties in Southern California. Subject to market conditions and other factors, Venoco may elect to effect an initial public offering of MLP units. Venoco currently expects that it would contribute 22% interests in certain of its key properties, which we refer to as the partnership properties, to the MLP contemporaneously with the closing of the public offering in exchange for cash and general and limited partner interests in the MLP. Venoco expects that the MLP would sell a majority of the limited partner interests in the MLP in the offering. At least 75% of the consideration Venoco would receive in the transaction would be in the form of cash. Venoco currently expects that the partnership properties would consist of 22% working interests in certain identified producing wells in the South Ellwood field, a 22% working interest in the Santa Clara Federal unit, a 22% working interest in the West Montalvo field, a 6% working interest in the Dos Cuadras field, and a 22% working interest in the Beverly Hills West field. As of December 31, 2012, the partnership properties had estimated proved reserves of 7.4 MMBOE and represented 14% of Venoco's estimated proved reserves. For the year ended December 31, 2012 and the nine months ended September 30, 2013, production from the partnership properties was 640 MBOE and 535 MBOE, respectively. Venoco would expect to use the cash proceeds of the contribution of assets to the MLP to reduce its outstanding indebtedness. We are unable to predict the amount of cash proceeds Venoco will receive if the transaction is completed. Our expectations regarding the nature and timing of, and the proceeds from, the transaction are subject to numerous risks and uncertainties, and there can be no assurance that the transaction will be completed in the time frame or manner we expect or at all. The foregoing does not constitute an offer to sell or the solicitation of an offer to buy any securities of the MLP.

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Capital Expenditures

In the first ~~six~~nine months of 2013 our development, exploitation and exploration capital expenditures were $4372 million, with approximately $3967 million incurred for Southern California legacy projects and $45 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 $7885 million is expected to be devoted to our legacy Southern California assets and approximately $136 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.

Southern California—Exploitation and Development

In ~~the first quarter of~~ 2013, we ~~successfully~~have ~~completed~~drilled ~~the~~three ~~3242-4~~wells ~~RD well to an~~ in~~-fill~~ ~~location at~~ the South Ellwood field. InAs ~~2013~~previously disclosed, we ~~have~~the ~~also~~most ~~drilled~~recent ~~two~~of ~~additional~~these wells inwas successfully ~~the~~completed ~~field, the 3242-15 well~~ and ~~the~~put ~~3242-19~~on ~~well.~~production ~~The~~in ~~3242-15~~July ~~well~~2013, ~~which~~but ~~was~~overall ~~drilled~~production tofrom ~~an in-fill location near~~ the ~~3242-4RD~~field ~~well~~did ~~and~~not ~~our~~increase ~~3242-12~~by ~~well, was recently completed and is in~~ the ~~dewatering~~full ~~phase,~~amount ~~but has produced at a maximum 24 hour rate~~ of ~~over~~production ~~1,000 BOE/d.~~attributed Into ~~June 2013,~~ the ~~3242-4RD~~ well ~~produced~~during atthat anmonth, ~~average gross~~potentially ~~rate~~indicating ofcommunication ~~approximately~~between ~~900 BOE/d,~~that ~~and the 3242-12~~ well ~~produced~~and atother anwells ~~average~~located ~~gross~~in ~~rate~~the ofsame ~~approximately~~bottom-hole ~~2,500 BOE/d~~vicinity. ~~The~~In ~~3242-19~~September ~~well~~2013, ~~which~~overall ~~was~~production ~~drilled~~from ~~to a probable location in a different part of~~ the field, iswas insimilar ~~the process of being completed and we expect~~ to ~~initiate~~production ~~testing~~shortly before the recent well ~~beginning~~was indrilled, ~~mid-August.~~further ~~During~~suggesting the ~~remainder~~possibility of ~~2013~~communication, wealthough ~~plan~~certain togas ~~replace~~handling ~~the~~capacity ~~existing de-rated~~issues ~~power~~have ~~cable~~adversely toaffected ~~Platform~~production ~~Holly.~~levels ~~The~~as ~~new~~well. ~~power~~During ~~cable~~a ~~will~~planned ~~provide~~shutdown of ~~us with~~ the ~~ability~~field toin ~~place~~October up2013, towe ~~three~~conducted ~~additional~~tests ~~gross~~designed ~~wells~~to ondetermine ~~electric~~whether ~~submersible~~communication ~~pumps~~is ~~(in lieu of gas lift)~~occurring, ~~which~~and ~~is expected~~are tocurrently ~~improve~~analyzing ~~our~~the ~~recovery~~data ~~capabilities~~we obtained.

During the third quarter of 2013, we replaced the existing de-rated power cable to Platform Holly. The new power cable will provide us with the ability to place additional 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 of 2013, and weduring ~~expect~~the tothird ~~complete~~quarter, ~~this~~we completed that well inand ~~the~~spud ~~third~~an ~~quarter~~additional well. ~~For~~During the ~~remainder~~fourth ~~of 2013~~quarter, we plan to ~~spud~~complete the ~~three~~well ~~additional~~spud ~~wells~~ in the ~~field~~third quarter and spud two additional wells. 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.

Southern California—Onshore Monterey Shale

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 59,000 gross and 52,000 net acres and is located primarily in three basins: Santa Maria, Salinas Valley and San Joaquin.

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~~Monterey~~ Since 2010, we have pursued an active drilling program targeting the onshore Monterey shale ~~acreage~~formation. ~~position~~From ~~currently~~that ~~totals~~time ~~approximately~~through 61September 30,~~000~~ ~~gross~~2013, we have spud 29 wells and 46have set casing on 26 of those wells. To date,~~000~~ ~~net~~we ~~acres~~have not seen material levels of production or reserves from the program and ishave, ~~located~~following ~~primarily~~the incompletion ~~three~~of ~~basins:~~the ~~Santa~~going ~~Maria~~private transaction, ~~Salinas~~reduced ~~Valley~~our capital expenditures related to the project. Based on the data we have gathered and ~~San~~the ~~Joaquin~~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.

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.

Other Acquisitions and Divestitures

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.

Trends Affecting our Results of Operations

Oil and Natural Gas Prices. Historically, prices received for our oil and natural gas production have been volatile and unpredictable, and that volatility is expected to continue. Changes in the market prices for oil and natural gas directly impact many aspects of our business, including our financial condition, revenues, results of operations, liquidity, rate of growth, carrying value of our oil and natural gas properties, value of our proved reserves and borrowing capacity under ~~our~~Venoco's 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~~November 112, 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 8693% to our legacy Southern California fields and 147% 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 and 2013 and the success of 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.

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~~increase in~~ Lease ~~capital~~Operating ~~spending~~Expenses. Lease ~~related~~operating toexpenses ~~our~~("LOE") ~~oil~~of ~~producing~~$20.39 ~~Southern~~per ~~California~~BOE ~~assets in 2012, the planned increase~~ for ~~2013 and~~ the ~~success~~first ofnine ~~two~~months of ~~our~~2013 ~~recently~~were ~~drilled~~higher ~~South~~than ~~Ellwood~~our ~~wells,~~full year we2012 ~~expect~~results ~~production~~of ~~from~~$14.48 ~~those~~per ~~assets to increase in 2013~~BOE. ~~Overall,~~We we expect ~~production~~that tothe becontinuing ~~significantly~~shift ~~lower~~ in ~~2013~~our ~~than~~focus ~~it was in 2012 due primarily~~ to ~~the~~oil ~~Sacramento~~development ~~Basin~~will ~~asset~~result ~~sale.~~in Onan aincrease ~~pro forma basis, excluding production from properties included~~ in ~~the~~our ~~asset~~LOE ~~sale,~~per weBOE ~~expect production to increase~~ in 2013 ~~compared~~relative to 2012.

~~Lease~~Property ~~Operating~~and ~~Expenses~~Production Taxes. ~~Lease~~Property ~~operating~~and ~~expenses~~production ~~("LOE")~~taxes of $190.6777 per BOE for the first ~~six~~nine months of 2013 were ~~higher~~lower than our ~~full~~ full year 2012 results of $141.4853 per BOE. We expect ~~that~~our ~~the~~2013 ~~continuing~~property ~~shift~~and inproduction ~~our~~taxes ~~focus~~ to ~~oil~~be ~~development~~lower ~~will~~on ~~result~~a inper anBOE ~~increase~~basis than they were in ~~our~~2012. ~~LOE~~Our ~~per~~ad ~~BOE~~valorem intax ~~2013~~expense ~~relative~~is highly sensitive to ~~2012~~drilling results and the estimated present value of future net cash flows from new wells, and may be volatile in the future.

~~Property~~Transportation ~~and Production Taxes~~Expenses. ~~Property~~Transportation ~~and~~expenses ~~production~~were ~~taxes of~~ $10.3705 per BOE for the first ~~six~~nine months of 2013 ~~were~~compared ~~slightly~~to ~~lower~~$0.81 ~~than our~~per BOE for the full year 2012. ~~results~~The ofdecrease ~~$1.53~~was ~~per~~due ~~BOE.~~to Wethe ~~expect~~elimination, ~~our~~in ~~2013~~mid-May ~~property~~2012, ~~and~~of ~~production~~the ~~taxes~~South toEllwood bebarge ~~higher~~operation onas a ~~per~~result ~~BOE~~of ~~basis~~the ~~than~~completion ~~they~~of ~~were~~the inonshore ~~2012.~~pipeline ~~Our~~during adthe ~~valorem~~first ~~tax~~quarter ~~expense~~of is2012. ~~highly~~We ~~sensitive~~expect that toour ~~drilling results~~transportation ~~and~~expenses ~~the~~will ~~estimated~~decrease ~~present~~in ~~value~~2013 ofcompared ~~future~~to ~~net~~2012 ~~cash~~as ~~flows~~a ~~from~~result ~~new~~of ~~wells,~~the ~~and~~use ~~may~~of bethe ~~volatile~~onshore inpipeline for the ~~future~~full year.

~~Transportation~~General and Administrative Expenses. ~~Transportation~~General and administrative expenses were $011.0400 per BOE (excluding non-cash share-based compensation charges of $2.77 per BOE) for the first ~~six~~nine months of 2013 compared to $06.8113 per BOE for the full year 2012 (excluding non-cash share-based compensation charges of $1.58 ~~The~~per ~~decrease~~BOE ~~was~~and ~~due~~costs of $1.76 per BOE related to the ~~elimination,~~going inprivate ~~mid~~transaction and one-~~May~~time ~~2012,~~Sacramento ofBasin ~~the~~exit ~~South~~and ~~Ellwood~~disposal ~~barge~~costs). ~~operation~~Excluding asshare-based acompensation ~~result~~charges ofand ~~the~~going ~~completion~~private-related ofcharges ~~the~~we ~~onshore~~expect ~~pipeline~~our ~~during~~2013 ~~the~~G&A costs ~~first~~to ~~quarter~~be ofslightly less than 2012., Weand, ~~expect that~~on ~~our~~a ~~transportation~~per ~~expenses~~BOE ~~will~~basis, ~~decrease~~to increase in 2013 compared to 2012 asdue 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 ~~result~~portion of the ~~use~~change, depending on the percentage of the ~~onshore~~requisite ~~pipeline~~service ~~for~~that has been rendered at the reporting ~~full~~date). ~~year~~As a result of these changes, our share-based compensation expense will likely fluctuate more than when these awards were equity based.

~~General~~ DPC incurs ~~and~~only ~~Administrative~~nominal ~~Expenses. General~~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~~nine months of 2013 was $1213.9461 per BOE compared to $13.68 per BOE for the full year 2012. We expect our 2013 DD&A to ~~decrease~~be similar on a per BOE basis compared to our 2012 results.

~~Unrealized~~Commodity Derivative Gains and Losses. ~~Unrealized~~We do not account for commodity derivative contracts as cash flow hedges. Commodity derivative gains and losses ~~result~~include ~~from~~settlements ~~mark-to-market~~of ~~valuations~~commodity derivative contracts, changes in fair value of open commodity derivative ~~positions~~ ~~that~~contracts ~~are~~and amortization of derivative premiums. The fair value of the open commodity ~~not~~derivative ~~accounted~~instruments ~~for~~will ascontinue ~~cash~~to ~~flow~~change ~~hedges~~in ~~and~~value until the transactions are ~~reflected~~settled. asTherefore, ~~unrealized~~we expect our net income to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time. Cash settlement of derivative ~~gains~~instruments orrepresents ~~losses~~the difference between the strike prices in ~~our~~contracts ~~income~~settled ~~statement~~during the period and the ultimate settlement prices. 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~~commodity derivative gains and losses in recent periods and may continue to incur these types of gains and losses in the future.

34 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

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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~~September 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.

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Results of Operations

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. Except for the items identified below as being specific to Venoco or DPC, all information shown is for both companies.

	Three Months Ended September 30,						Nine Months Ended September 30,

	2012			2013			2012			2013
Production Volume(1):
Oil (MBbls)		839			786			2,172			2,449
Natural gas (MMcf)		4,846			272			15,688			1,412
MBOE(2)		1,647			831			4,787			2,684
Daily Average Production Volume:
Oil (Bbls/d)		9,120			8,543			7,927			8,971
Natural gas (Mcf/d)		52,674			2,957			57,255			5,172
BOE/d(2)		17,899			9,036			17,470			9,833
Oil Price per Bbl Produced (in dollars):
Realized price	$	96.20		$	99.16		$	98.26		$	97.36
Realized commodity derivative gain (loss)		(9.68	)		(5.42	)		(8.34	)		(5.93	)

Net realized price	$	86.52		$	93.74		$	89.92		$	91.43

Natural Gas Price per Mcf (in dollars):
Realized price	$	2.86		$	4.19		$	2.67		$	3.97
Realized commodity derivative gain (loss)		0.11			—			0.40			—

Net realized price	$	2.97		$	4.19		$	3.07		$	3.97

Expense per BOE:
Lease operating expenses	$	13.90		$	21.99		$	14.09		$	20.39
Property and production taxes		1.01			(0.57	)		1.79			0.77
Transportation expenses		0.29			0.06			1.08			0.05
Depreciation, depletion and amortization		13.50			15.10			13.73			13.61
Venoco:
General and administrative expense, net(3)		7.18			6.45			7.11			11.44
Interest expense		10.02			18.86			10.05			19.35
Denver Parent Corporation:
General and administrative expense, net(3)		7.18			6.48			7.11			11.50
Interest expense		10.02			25.40			10.05			24.34

(1): Amounts shown are oil production volumes for offshore properties and sales volumes for onshore properties (differences between onshore production and sales volumes are minimal). Revenue accruals are adjusted for actual sales volumes since offshore oil inventories can vary significantly from month to month based on pipeline inventories, oil pipeline sales nominations, and prior to February 2012, the timing of barge deliveries and oil in tanks.
(2): BOE is determined using the ratio of one barrel of oil or natural gas liquids to six Mcf of natural gas.
(3): Net of amounts capitalized.

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~~the comparability~~ Comparison of ~~the~~Quarter ~~data~~Ended ~~below.~~September 30, ~~The~~2013 ~~information~~to ~~set~~Quarter ~~forth~~Ended ~~below~~September 30, ~~is not necessarily indicative of future results.~~ 2012

	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 decreased $15.7 million (16%) to $79.7 million in the third quarter of 2013 compared to $95.4 million in the third quarter of 2012. The decrease was due to lower oil and natural gas production, partially offset by higher realized oil prices, as described below.

Oil sales ~~Comparison~~decreased by $3.0 million (4%) in the third quarter of ~~Quarter~~2013 ~~Ended~~to ~~June~~$78.5 30million compared to $81.5 million in the third quarter of 2012. Oil production decreased by 6%, with production of 786 MBbls in the third quarter of 2013 compared to ~~Quarter~~839 ~~Ended~~MBbls ~~June 30~~in the third quarter of 2012. The decrease is primarily due to lower production at our West Montalvo field, resulting from downhole repairs and delays in the drilling program. Our average realized price for oil increased $2.96 per Bbl (3%) from $96.20 per Bbl in the third quarter of 2012 to $99.16 per Bbl for the third quarter of 2013.

~~Oil and~~ Natural gas ~~Gas~~sales ~~Sales~~decreased $12. ~~Oil~~8 million ~~and~~(92%) ~~natural~~in ~~gas~~the ~~sales~~third ~~increased~~quarter of 2013 to $01.51 million ~~(1%)~~compared to $8113.49 million in the ~~second~~third quarter of 2012. Natural gas production decreased by 94% in the third quarter of 2013 , with production of 272 MMcf compared to ~~$80.9 million~~4,846 MMcf in the ~~second~~third quarter of 2012. The ~~increase~~decrease ~~was~~is primarily due to ~~higher~~the ~~oil~~sale ~~production,~~of ~~partially~~Sacramento ~~offset~~Basin assets. byOur ~~lower~~average realized price for natural gas ~~production,~~increased as$1.33 ~~described~~per ~~below~~Mcf (47%) from $2.86 per Mcf in the third quarter of 2012 to $4.19 per Mcf in the third quarter of 2013.

~~Oil sales~~ Other ~~increased by $11~~Revenues.~~6 million~~ Other ~~(17%)~~revenues inremained ~~the~~relatively ~~second~~constant ~~quarter~~at ~~of 2013 to~~ $801.23 million ~~compared to $68.6 million~~ in the ~~second~~third quarter of 2012. ~~Oil~~and ~~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~~

36 Lease Operating Expenses. Lease operating expenses ("LOE") decreased $4.6 million (20%) in the third quarter of 2013 to $18.3 million compared to $22.9 million in the third 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 decreased $0.3 million (2%) in the third quarter of 2013 to $18.3 million compared to $18.6 million in the third quarter of 2012. On a per unit basis, LOE increased by $8.09 per BOE from $13.90 in the third quarter of 2012 to $21.99 in the third quarter of 2013. Excluding the Sacramento Basin assets sold, on a per unit basis, LOE increased by $0.74 per BOE from $21.25 in the third quarter of 2012 to $21.99 in the third quarter of 2013.

Property and Production Taxes. Property and production taxes decreased $2.2 million (128%) in the third quarter of 2013 to $(0.5) million compared to $1.7 million in the third quarter of 2012. The decrease is primarily due to revised estimates for supplemental property taxes at our South Ellwood and West Montalvo fields. On a per BOE basis, property and production taxes decreased $1.58 per BOE to $(0.57) in the third quarter of 2013 from $1.01 in the third quarter of 2012.

Transportation Expenses. Transportation expenses decreased $0.5 million (90%) to $50,000 in the third quarter of 2013 compared to $0.5 million in the third 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.

Depletion, Depreciation and Amortization (DD&A). DD&A expense decreased $9.7 million (44%) to $12.5 million in the third quarter of 2013 compared to $22.2 million in the third 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 $1.9 million (18%) to $12.5 million in the third quarter of 2013 compared to $10.6 million in the third quarter of 2012. This increase is primarily due to a higher depletion rate in the third quarter of 2013 primarily as a result of an increase in future development costs related to additional proved undeveloped locations recorded during the quarter. DD&A expense on a per unit basis increased $1.60 per BOE to $15.10 per BOE for the third quarter of 2013 compared to $13.50 per BOE for the third quarter of 2012.

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~~drilling activity.~~ Accretion ~~Our~~of ~~average~~Abandonment ~~realized~~Liability. Accretion ~~price~~expense ~~for oil~~ decreased $60.929 million ~~per Bbl~~ (759%) ~~from~~to $~~100~~0.386 million ~~per~~in ~~Bbl~~the third quarter of 2013 compared to $1.5 million in the ~~second~~third quarter of 2012. toThe ~~$93.46~~decrease ~~per~~is ~~Bbl~~primarily ~~for~~the result of the ~~second~~Sacramento ~~quarter~~Basin ofasset ~~2013~~sale.

~~Natural gas~~General ~~sales~~and ~~decreased~~Administrative ~~$11.1 million~~ (~~90%~~G&A) ~~in the second quarter of 2013 to $1~~.~~2 million~~ The ~~compared~~following totable ~~$12.3 million~~summarizes in the ~~second~~components ~~quarter~~ of ~~2012.~~Venoco's ~~Natural~~general ~~gas production~~and ~~decreased~~administrative byexpense incurred ~~95%~~during 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~~periods ~~assets.~~indicated ~~Our average realized price for natural gas increased $2.20 per Mcf~~ (~~92%) from $2.38 per Mcf~~ in ~~the~~thousands): ~~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.

	Three Months Ended September 30,

	2012			2013
General and administrative costs	$	14,779		$	10,899
Share-based compensation costs		1,790			(2,890	)
Going private related costs (none capitalized)		1,277			—
General and administrative costs capitalized		(6,024	)		(2,651	)

General and administrative expense, net of amounts capitalized	$	11,822		$	5,358

~~Lease~~Venoco G&A ~~Operating Expenses. Lease operating~~ expenses ~~("LOE")~~ decreased $26.25 million (1155%) to $5.3 million in the ~~second~~third quarter of 2013 ~~to $17.9 million~~ compared to $2011.18 million in the ~~second~~third quarter of 2012. The decrease ~~was~~ is primarily due tolower ~~the~~share-based ~~sale~~compensation expense of ~~Sacramento Basin assets~~$(2.2) ~~Excluding~~million ~~the~~(net ~~Sacramento~~of ~~Basin~~amount ~~assets~~capitalized) ~~included~~charged into ~~the~~G&A ~~sale, LOE increased $1.5 million (9%)~~ in the ~~second~~third quarter of 2013 compared to $171.93 million ~~compared~~(net toof ~~$16.4 million~~amount capitalized) in the ~~second~~third quarter of 2012., Inand ~~the~~lower ~~second~~estimated ~~quarter~~bonus ofexpenses in 2013. weIn ~~incurred higher~~connection ~~non-recurring~~with ~~repairs~~the atgoing private transaction, our ~~West~~equity ~~Montalvo~~based ~~field~~awards ~~than~~were inconverted ~~the~~into ~~second~~cash ~~quarter~~settlement of(or liability) ~~2012~~awards. OnAs a ~~per~~result ~~unit~~of ~~basis~~these changes, ~~LOE~~we ~~increased~~expect bythat ~~$7.04~~our ~~per~~share-based ~~BOE~~compensation ~~from~~expense ~~$12.93~~will inlikely ~~the~~fluctuate ~~second~~more ~~quarter~~than ofwhen ~~2012~~these toawards ~~$19.97~~were ~~in the~~equity ~~second quarter of 2013~~based. Excluding the ~~Sacramento~~effect ~~Basin~~of ~~assets~~the non-cash ~~sold,~~share-based oncompensation aexpense ~~per~~and ~~unit~~going ~~basis~~private related costs, ~~LOE~~G&A expense decreased byto $26.7545 per BOE ~~from $22.73~~ in the ~~second~~third quarter of ~~2012~~2013 tofrom $197.9818 per BOE in the ~~second~~third quarter of ~~2013~~ 2012.

~~Property~~ DPC incurred ~~and~~nominal ~~Production~~G&A ~~Taxes. Property~~expenses ~~and~~during ~~production taxes decreased $3.9 million (73%) in~~ the ~~second~~third 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 $131,000.84 ~~per BOE to $1.57 in the second quarter of 2013 from $3.41 in the second quarter of 2012.~~

~~Transportation~~ Interest ~~Expenses~~Expense. ~~Transportation~~For ~~expenses~~Venoco, interest expense decreased $0.28 million (825%) to $~~45,000~~15.7 million in the ~~second~~third quarter of 2013 compared to $016.35 million in the ~~second~~third quarter of 2012. The decrease was ~~due~~primarily tothe ~~elimination,~~result inof ~~mid-May~~the ~~2012,~~repayment of the ~~South~~11.50% ~~Ellwood~~senior ~~barge~~notes ~~operation~~in asthe athird ~~result~~quarter of 2013. For DPC, interest expense increased $4.6 million (28%) to $21.1 million in the ~~completion~~third quarter of ~~the~~2013 ~~onshore~~compared ~~pipeline during~~to $16.5 million in the ~~second~~third quarter of 2012. The incremental increase of $5.4 million from Venoco's total interest was due to interest on DPC's 12.25% / 13.00% senior PIK toggle notes and, prior to their redemption, DPC's senior secured notes.

~~Depletion,~~Amortization ~~Depreciation~~of ~~and~~Deferred ~~Amortization~~Loan ~~(DD&A)~~Costs. ~~DD&A~~For ~~expense~~Venoco, ~~decreased~~amortization of deferred loan costs increased $80.83 million (4245%) to $120.49 million in ~~the~~ ~~second~~the third quarter of 2013 compared to $210.26 million in the ~~second~~third quarter of 2012. ~~The~~For ~~decrease~~DPC, ~~was~~amortization ~~primarily due to the sale~~ of ~~the~~deferred ~~Sacramento~~loan ~~Basin~~costs ~~assets. Excluding the Sacramento Basin assets sold, DD&A~~ increased $30.86 million (4493%) to $121.42 million in the third ~~second~~ quarter of 2013 compared to $80.6 million in the ~~second~~third quarter of 2012. ~~This~~The ~~increase~~costs isincurred ~~primarily~~relate ~~due~~ to ~~higher production at~~ our ~~South~~loan ~~Ellwood~~agreements and ~~West~~are ~~Montalvo~~amortized ~~fields,~~over ~~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~~estimated ~~quarter~~ lives of ~~2013 compared to $13.65 per BOE for~~ the ~~second quarter of 2012~~agreements.

~~Accretion~~Loss ofon ~~Abandonment~~Extinguishment ~~Liability~~of Debt. ~~Accretion~~For ~~expense~~Venoco, ~~decreased~~the ~~$0.9 million~~loss ~~(58%)~~on toextinguishment of debt of $016.68 million in the ~~second~~third quarter of 2013 ~~compared~~resulted tofrom a write-off of unamortized deferred loan costs, unamortized original issue discount and a premium paid for early repayment of Venoco's 11.50% senior notes. For DPC, the loss on extinguishment of debt of $136.57 million in the ~~second~~third quarter of ~~2012.~~2013 ~~The~~resulted ~~decrease~~from isa ~~primarily~~write-off ~~the~~of ~~result~~unamortized deferred loan costs, unamortized original issue discount and a premium paid for early repayment of ~~the~~Venoco's 11.50% ~~Sacramento~~senior ~~Basin~~notes ~~asset~~and ~~sale~~DPC's secured notes.

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

	Three Months Ended 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

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):

	Three Months Ended June 30,
	Three Months Ended September 30,
	2012			2013
Realized commodity derivative losses (gains)	$	(67,~~786~~597	)	$	54,~~132~~261
Amortization of commodity derivative premiums		21,~~224~~203			1,~~018~~017
Unrealized commodity derivative losses (gains) for changes in fair value		(240,~~134~~289	)		~~(26~~8,~~101~~893	)
Commodity derivative losses (gains), net	$	(649,~~696~~089	)	$	~~(19~~14,~~951~~171	)

38 Income Tax Expense (Benefit). Due to our valuation allowance, there was no income tax expense (benefit) recorded for the quarters ended September 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). For Venoco, the net loss for the third quarter of 2013 was $2.9 million compared to the net loss of $30.1 million for the same period in 2012. For DPC, the net loss for the third quarter of 2013 was $28.6 million compared to the net loss of $30.1 million for the same period in 2012. The changes between periods is the result of the items discussed above.

Comparison of Nine Months Ended September 30, 2013 to Nine Months Ended September 30, 2012

Oil and Natural Gas Sales. Oil and natural gas sales decreased $12.6 million (5%) to $247.1 million in the nine months ended September 30, 2013 compared to $259.7 million for the same period in 2012. The decrease was due to lower natural gas production, partially offset by higher oil production, as described below.

Oil sales increased by $23.6 million (11%) in the nine months ended September 30, 2013 to $241.5 million compared to $217.9 million for the same period in 2012. Oil production increased by 13%, with production of 2,449 MBbls in the first nine months of 2013 compared to 2,172 MBbls in the first nine months 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 $0.90 per Bbl (1%) from $98.26 per Bbl in the first nine months of 2012 to $97.36 per Bbl for the first nine months of 2013.

Natural gas sales decreased $36.2 million (87%) in the first nine months of 2013 to $5.6 million compared to $41.8 million in the first nine months of 2012. Natural gas production decreased by 91% in the first nine months of 2013, with production of 1,412 MMcf compared to 15,688 MMcf in the first nine months of 2012. The decrease is primarily due to the sale of Sacramento Basin assets. Our average realized price for natural gas increased $1.30 per Mcf (49%) from $2.67 per Mcf in the first nine months of 2012 to $3.97 per Mcf in the first nine months of 2013.

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~~realizing total~~ Other ~~losses~~Revenues. Other revenues decreased $1.4 million (29%) in the first nine months of 2013 to $3.65 million compared to $4.9 million ~~Unrealized~~in ~~commodity~~the ~~derivative~~first ~~(gains)~~nine ~~losses~~months ~~represent~~of 2012. During the ~~change~~first innine ~~the~~months ~~fair~~of ~~value~~2012, we received revenues related to sub-charter activity of ~~our~~the ~~open~~barge ~~derivative~~used ~~contracts~~to transport oil production from ~~period~~our toSouth ~~period~~Ellwood field. ~~Derivative premiums~~Our ~~are~~contract ~~amortized~~related ~~over~~to the ~~term~~barge ofwas terminated effective in mid-May 2012; therefore, we did not realize any sub-charter revenue in the ~~underlying~~first nine ~~derivative~~months ~~contracts~~of 2013.

~~Income~~Lease ~~Tax~~Operating ~~Expense~~Expenses. Lease operating expenses (~~Benefit~~"LOE") decreased $12. ~~Due~~7 million (19%) in the first nine months of 2013 to $54.7 million ~~our~~compared ~~valuation~~to ~~allowance,~~$67.4 million ~~there~~in the first nine months of 2012. The decrease was noprimarily ~~income~~due ~~tax~~to ~~expense~~the ~~(benefit)~~sale ~~recorded~~of ~~for~~Sacramento Basin assets. Excluding the ~~quarters~~Sacramento ~~ended~~Basin assets ~~June 30~~included in the sale, LOE decreased $0.7 million (1%) in the first nine months of 2013 orto ~~2012~~$54.7 million Ascompared ~~long~~to as$55.4 million wein ~~continue~~the first nine months of 2012, due primarily to ~~conclude~~non-recurring ~~that~~repair wecosts ~~have~~incurred aat ~~need~~our ~~for~~South Ellwood field in the first nine months of 2012. On a ~~full~~per ~~valuation~~unit ~~allowance~~basis, ~~against~~LOE ~~our~~increased ~~net~~by ~~deferred~~$6.30 ~~tax~~per BOE from $14.09 in the first nine months of 2012 to $20.39 in the first nine months of 2013. Excluding Sacramento Basin assets sold, weon ~~likely~~a ~~will~~per ~~not~~unit ~~have~~basis, ~~any~~LOE ~~income~~decreased ~~tax~~by ~~expense or~~$3.98 ~~benefit~~per ~~other~~BOE ~~than~~from ~~for~~$24.37 ~~federal~~in ~~alternative~~the ~~minimum~~first ~~tax~~nine ~~expense~~months orof ~~for~~2012 ~~state~~to ~~income~~$20.39 ~~taxes~~in the first nine months of 2013.

~~Net~~Property ~~Income~~and ~~(Loss)~~Production Taxes. ~~Net~~Property ~~income~~and ~~for~~production taxes decreased $6.5 million (76%) in the ~~second~~first ~~quarter~~nine months of 2013 ~~was~~ to $~~41.~~2.1 million compared to ~~net income of~~ $148.56 million ~~for~~ in the ~~same period~~first innine months of 2012. The ~~change~~decrease ~~between periods~~ is primarily the result of revised estimates for supplemental property taxes at our South Ellwood and West Montalvo fields. On a per BOE basis, property and production taxes decreased $1.02 per BOE to $0.77 in the ~~items~~first ~~discussed~~nine ~~above~~months of 2013 from $1.79 in the first nine months of 2012.

Transportation ~~Comparison~~Expenses. Transportation ofexpenses ~~Six~~decreased ~~Months~~$5.1 million ~~Ended~~(97%) ~~June~~to $0.1 ~~30,~~million in the first nine months of 2013 compared to ~~Six~~$5.2 million ~~Months~~in ~~Ended~~the ~~June 30~~first nine months 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.

~~Oil~~Depletion, Depreciation and ~~Natural~~Amortization ~~Gas Sales~~(DD&A). ~~Oil~~DD&A ~~and~~expense ~~natural~~decreased ~~gas~~$29.2 million ~~sales~~(44%) to $36.5 million in the first nine months of 2013 compared to $65.7 million in the first nine months of 2012. The decrease was primarily due to the sale of the Sacramento Basin assets. Excluding the Sacramento Basin assets sold, DD&A increased $37.10 million (223%) to $~~167~~36.45 million in the first ~~half~~nine months of 2013 compared to $~~164~~29.35 million in the first ~~half~~nine months of 2012. ~~The~~This increase ~~was~~is primarily due to higher production ~~oil~~at ~~production~~our South Ellwood field, ~~partially~~resulting ~~offset~~from bysuccessful ~~lower~~drilling ~~natural~~activity. ~~gas~~DD&A ~~production,~~expense ason ~~described~~a ~~below~~per unit basis decreased $0.12 per BOE to $13.61 per BOE for the first nine months of 2013 compared to $13.73 per BOE for the first nine months of 2012.

~~Oil sales~~ Accretion ~~increased~~of byAbandonment Liability. Accretion expense decreased $262.64 million (2057%) ~~in the first half of 2013~~ to $~~162~~1.9 million ~~compared to $136.3 million~~ in the first ~~half~~nine ~~of 2012. Oil production increased~~months ~~by 25%, with production~~ of ~~1,663 MBbls in the first half of~~ 2013 compared to ~~1,333~~$4.3 million ~~MBbls~~ in the first ~~half~~nine months of 2012. The ~~increase~~decrease 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~~result ~~half~~ of ~~2012 to $96.51 per Bbl for~~ the ~~first~~Sacramento ~~half~~Basin ofasset ~~2013~~sale.

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. 43

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

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~~reserves from~~ General ~~new wells. On a per BOE basis, property~~ and ~~production~~Administrative ~~taxes decreased $0~~(G&A).83 The ~~per~~following ~~BOE~~table tosummarizes ~~$1.37 in~~ the ~~first~~components ~~half~~ of ~~2013~~Venoco's ~~from~~general ~~$2.20~~and inadministrative ~~the~~expense incurred ~~first~~during ~~half~~the periods ofindicated ~~2012.~~(in thousands):

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.

	Nine Months Ended September 30,

	2012			2013
General and administrative costs	$	43,176		$	35,697
Share-based compensation costs		5,850			9,695
Going private related costs (none capitalized)		4,757			—
General and administrative costs capitalized		(19,731	)		(14,684	)

General and administrative expense, net of amounts capitalized	$	34,052		$	30,708

~~Depletion, Depreciation and Amortization (DD~~ Venoco G&A~~). DD&A~~ ~~expense~~expenses decreased $193.54 million (4510%) to $2430.07 million in the first ~~half~~nine months of 2013 compared to $4334.51 million in the first ~~half~~nine months of 2012. The decrease ~~was~~is primarily due to ~~the~~lower ~~sale~~employee ofrelated G&A in the ~~Sacramento~~first ~~Basin~~nine ~~assets.~~months ~~Excluding~~of 2013 due to the Sacramento Basin ~~assets~~asset ~~sold~~sale, ~~DD&A~~offset ~~increased~~by higher share-based compensation expense of $57.54 million (~~30%~~net of amount capitalized) charged to ~~$24.0 million~~G&A in the first ~~half~~nine months of 2013 compared to $183.56 million (net of amount capitalized) in the first ~~half~~nine months of 2012. ~~This~~In connection ~~increase~~with isthe ~~primarily~~going ~~due~~private totransaction, ~~higher~~our ~~production~~equity atbased ~~our~~awards ~~South Ellwood~~were ~~field,~~converted ~~resulting~~into ~~from~~cash ~~successful~~settlement ~~drilling~~(or ~~activity~~liability) awards. ~~DD&A~~As a result of these changes, we expect that our share-based compensation expense onwill alikely ~~per~~fluctuate ~~unit~~more ~~basis~~than ~~decreased~~when $0these awards were equity based.90 ~~per~~Excluding ~~BOE~~the effect of the non-cash share-based compensation expense and going private related costs, G&A expense increased to $1211.9444 per BOE ~~for~~in the first ~~half~~nine months of 2013 ~~compared~~from to $137.8411 per BOE ~~for~~in the first ~~half~~nine months of 2012.

~~Accretion~~ DPC incurred ofnominal ~~Abandonment~~G&A ~~Liability. Accretion~~expenses ~~expense decreased $1.5 million (55%) to $1.3 million~~ in the first ~~half~~nine months of 2013 ~~compared to~~ of $20.82 million ~~in the first half of 2012~~. ~~The decrease is primarily the result of the Sacramento Basin asset sale.~~

~~General~~ Interest ~~and~~Expense. For ~~Administrative~~Venoco, interest expense increased $3.8 million (~~G&A~~8%) to $51. 9 million in the first nine months of 2013 compared to $48.1 million in the first nine months of 2012. The ~~following~~increase ~~table~~was ~~summarizes~~primarily the ~~components~~result of ~~general~~the issuance of the $315 million second lien term loan in connection with the going private transaction and ~~administrative~~additional ~~expense~~revolver borrowings incurred ~~during~~ to repay the ~~periods indicated~~second lien term loan. For DPC, interest expense increased $17.2 million (36%) to $65.3 million in ~~thousands):~~the first nine months of 2013 compared to $48.1 million in the first nine months of 2012. The incremental increase of $13.4 million from Venoco's total interest was due to interest on DPC's 12.25% / 13.00% senior PIK toggle notes and, prior to their redemption, DPC's senior secured notes.

	Six Months Ended June 30,
	2012			2013
General and administrative costs	$	28,397		$	24,798
Share-based compensation costs		4,060			12,585
Going private related costs (none capitalized)		3,480			—
General and administrative costs capitalized		(13,707	)		(12,033	)
General and administrative expense, net of amounts capitalized	$	22,230		$	25,350

Amortization of Deferred Loan Costs. For Venoco, amortization of deferred loan costs increased $1.1 million (65%) to $2.9 million in the first nine months of 2013 compared to $1.8 million in the first nine months of 2012. For DPC, amortization of deferred loan costs increased $1.9 million (113%) to $3.7 million in the first nine months of 2013 compared to $1.8 million in the first nine months of 2012. The costs incurred relate to our loan agreements and are amortized over the estimated lives of the agreements.

~~G&A expenses~~ Loss ~~increased~~on ~~$3.2 million~~Extinguishment ~~(14%) to $25.4 million in the first half~~ of ~~2013 compared to $22~~Debt.~~2 million~~ For inVenoco, the ~~first~~loss ~~half~~on extinguishment of ~~2012.~~debt ~~The increase is primarily due to higher share-based compensation expense~~ of $938.61 million ~~(net of amount capitalized) charged to G&A~~ in the first ~~half~~nine months of 2013 resulted ~~compared~~from a towrite-off ~~$2.2 million (net~~ of ~~amount~~unamortized ~~capitalized) in~~deferred ~~the~~loan ~~first half of 2012~~costs, ~~partially~~unamortized ~~offset~~original byissue ~~lower~~discount ~~employee~~and ~~related~~a ~~G&A~~premium inpaid ~~the~~for ~~first~~early ~~half~~repayment of ~~2013~~Venoco's ~~due~~second tolien ~~the~~term ~~Sacramento~~loan ~~Basin~~and ~~asset sale~~11.50% Insenior ~~connection~~notes. ~~with~~For ~~the going private transaction~~DPC, ~~our~~loss ~~equity~~on ~~based~~extinguishment ~~awards~~of ~~were~~debt ~~converted~~was ~~into~~$58.0 million ~~cash~~in ~~settlement~~the ~~(or~~first ~~liability)~~nine ~~awards.~~months ~~As a result~~ of ~~these~~2013. ~~changes,~~The weincremental ~~expect~~increase ~~that~~of ~~our~~$19.9 million ~~share-based~~from ~~compensation~~Venoco's ~~expense~~total ~~will~~loss ~~likely~~on beextinguishment ~~higher~~of indebt ~~2013~~was ~~and~~due ~~will~~to ~~likely~~a ~~fluctuate~~write-off ~~more than when these awards were equity based. Excluding the effect~~ of ~~the~~unamortized ~~non-cash~~deferred ~~share-based~~loan ~~compensation~~costs ~~expense~~ and ~~going~~a ~~private~~premium ~~related~~paid ~~costs,~~for ~~G&A~~early ~~expense~~repayment ~~increased to $11.78 per BOE in the first half~~ of ~~2013~~DPC's ~~from~~secured $5notes.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. 44

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.

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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.

	Six Months Ended June 30,
	Nine Months Ended September 30,
	2012			2013
Realized commodity derivative losses (gains)	$	(4740,~~882~~285	)	$	1924,~~749~~010
Amortization of commodity derivative premiums		1011,~~019~~222			12,~~967~~984
Unrealized commodity derivative losses (gains) for changes in fair value		61101,~~705~~994			(3829,~~324~~431	)
Commodity derivative losses (gains), net	$	2372,~~842~~931		$	(162,~~608~~437	)

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~~nine months of 2013 reflect the settlement of contracts at prices above the relevant strike prices. In ~~addition, in~~ the first ~~half~~nine months 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~~Additionally, ~~realized~~we ~~commodity~~unwound ~~gains~~certain inoil ~~the~~and ~~first~~natural ~~half~~gas ~~of 2012 reflect the settlement of~~ contracts ~~below the relevant strike prices. In addition,~~ in the first ~~quarter~~nine months of 2012 ~~we unwound certain natural gas derivative contracts~~ and realized a gain of $4152.2 million which is reflected in realized commodity derivative (gains) losses. Unrealized commodity derivative (gains) losses represent the change in the fair value of our open derivative contracts from period to period. Derivative premiums are amortized over the term of the underlying derivative contracts.

Income Tax Expense (Benefit). Due to our valuation allowance, there was no income tax expense (benefit) recorded in the ~~six~~nine month periods ended ~~June~~September 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~~ expense or benefit other than for federal alternative minimum tax expense or for state income taxes.

Net Income (Loss). ~~Net~~For Venoco, net income for the first ~~half~~nine months of 2013 was $3734.1 million compared to the net loss of $43.4 million for the same period in 2012. For DPC, the net loss for the first nine months of 2013 was $0.2 million compared to the net loss of $1343.4 million for the same period in 2012. The ~~change~~ changes between periods is the result of the items discussed above.

Liquidity and Capital Resources

~~Our~~Venoco's primary sources of liquidity are cash generated from our operations and amounts available under ~~our~~its revolving credit facility. DPC's primary sources of liquidity are distributions from Venoco and the issuance of debt securities.

Cash Flows

	Six Months Ended June 30,
	Venoco, Inc.						Denver Parent Corporation
	2012			2013
	Nine Months Ended September 30,						Nine Months Ended September 30,
	(in thousands)
	2012			2013			2012			2013
Cash (used in) provided by operating activities	$	99,931		$	39,495
	(in thousands)
Cash (used in) provided by investing activities		(110,117	)		52,769
Cash (used in) provided by operating activities	$	134,320		$	61,864		$	134,320			57,638
Cash (used in) provided by financing activities		2,040			(142,566	)
Cash (used in) provided by investing activities		(155,966	)		19,389			(155,966	)		19,389
Cash (used in) provided by financing activities		31,689			(135,055	)		31,689			(114,105	)

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Net cash provided by operating activities for Venoco was $3961.59 million in the first ~~half~~nine months of 2013 compared to net cash provided by operating activities of $99134.93 million in the 2012 period. Cash flows used in operating activities in the first ~~half~~nine months of 2013 as compared to the 2012 period were impacted by increased cash flows from higher oil production offset by cash outflows of $1924.70 million for realized commodity derivative losses, higher interest expense of $43.78 million, and greater share-based compensation expense of $~~10.~~8.3 million for cash settled awards. Cash flows from operating activities in the first ~~half~~nine months of 2012 were favorably impacted by athe realized gain of $52.2 million from the early settlement of oil and natural gas derivative contracts.

Net cash provided by ~~investing~~operating activities for DPC was $5257.86 million in the first ~~half~~nine months of 2013 compared to ~~net cash used in investing activities of~~ $~~110~~61.19 million infor ~~the~~Venoco ~~2012 period. The primary investing activities~~ in the ~~first~~same 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 programperiod. The ~~primary investing activities~~ difference in the ~~first~~amounts ~~half~~between ofVenoco ~~2012 were $132 million in capital expenditures on oil~~ and ~~natural~~DPC ~~gas~~relates ~~properties related~~ to ~~our~~additional ~~capital~~DPC ~~expenditure~~interest ~~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~~expense.

Net cash ~~used~~provided inby ~~financing~~investing activities for Venoco and DPC was $~~142~~19.64 million in the first ~~half~~nine months of 2013 compared to net cash ~~provided~~used byin ~~financing~~investing activities of $2156.0 million ~~during~~in the 2012 period. The primary ~~financing~~investing activities in the first ~~half~~nine months of 2013 were ~~(i)~~sales ~~repayment~~proceeds of $~~315~~101 million onreceived ~~our~~as ~~second lien term loan with~~ a ~~combination~~ result of the Sacramento Basin asset sale, ~~proceeds~~partially ofoffset by $~~208~~81 million ~~and~~in ~~borrowings~~capital expenditures on oil properties related to our ~~revolving~~capital ~~credit~~expenditure ~~facility~~program. ofThe ~~$107~~primary ~~million~~investing ~~and~~activities ~~(ii)~~in ~~net~~the ~~additional~~first ~~borrowings~~nine months of 2012 were $76176.7 million in capital expenditures on ~~our~~ ~~revolving~~oil ~~credit~~and ~~facility.~~natural ~~The~~gas ~~primary~~properties ~~financing~~related ~~activities~~to inour ~~the~~capital ~~first~~expenditure ~~half~~program, ofpartially ~~2012~~offset ~~were~~by $223.4 million in net ~~borrowings~~cash ~~under~~proceeds received from the sale of our ~~revolving~~Santa ~~credit~~Clara ~~facility~~Avenue field in the second quarter of 2012.

Net cash used in financing activities for Venoco was $135.1 million in the first nine months of 2013 compared to net cash provided by financing activities of $31.7 million during the 2012 period. The primary financing activities in the first nine months of 2013 were (i) repayment of $315 million on Venoco's second lien term loan with a combination of Sacramento Basin asset sale proceeds of $208 million and borrowings on its revolving credit facility of $107 million, (ii) repayment of its 11.50% senior notes which was funded by a capital contribution from DPC to Venoco of $158 million, (iii) net additional borrowings of $101 million on its revolving credit facility, (iv) prepayment premiums of $19.9 million incurred for the repayment of the second lien term loan and the 11.50% senior notes and, (v) a dividend of $15.8 million paid to DPC. Venoco's primary financing activities in the first nine months of 2012 were $32 million in net borrowings under its revolving credit facility.

Net cash used in financing activities for DPC was $114.1 million in the first nine months of 2013. DPC's incremental financing activities compared to Venoco's financing activities for the first nine months of 2013 were the repayment of DPC's secured notes for $81.7 million, including $16.7 million of redemption premium, and new borrowings under the DPC 12.25% / 13.00% senior PIK toggle notes of $248.2 million.

Capital Resources and Requirements

We plan to make substantial capital expenditures in the future for the acquisition, exploration, exploitation and development of oil and natural gas properties. Our 2013 exploration, exploitation and development capital expenditures budget is currently $91 million and through the first ~~half~~nine months of 2013, we have incurred $4372 million. We expect to fund these expenditures primarily with cash flow from operations, supplemented with borrowings under ~~our~~Venoco's 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~~ 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.

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~~Revolving Credit Facility. In October 2012, we entered into a fifth amended and restated credit agreement governing our revolving~~effects ~~credit facility, which has a maturity date~~ of ~~March 31,~~changes ~~2016.~~in ~~The~~commodity ~~agreement~~prices ~~contains customary representations, warranties, events of default, indemnities~~ and ~~covenants~~differentials, ~~including~~ ~~covenants~~results ~~that~~from ~~restrict~~ our ~~ability~~drilling ~~to incur indebtedness~~ and ~~require~~other usdevelopment ~~to maintain specified ratios of current assets to current liabilities~~activities, ~~debt to EBITDA~~ and ~~interest coverage. The agreement also limits~~ the ~~amount~~possibility ofthat ~~exploratory capital spending~~ we ~~can~~will ~~incur~~pursue onone ~~our~~or ~~onshore~~more ~~Monterey~~significant ~~program~~acquisitions ~~if our debt to EBITDA ratio exceeds 3.75 to 1.00. The minimum ratio of current assets to~~that ~~current~~would ~~liabilities~~require ~~(as~~additional 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 toor ~~EBITDA~~equity ~~was changed to 5~~financing.75 ~~to 1.00 through September 30, 2013, stepping down over time to 4.00 to 1.00 by September 30, 2014.~~ As ~~amended,~~described ~~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~~below, the ~~amendment~~terms 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~~our ~~additional~~ debt ~~incurred~~agreements incontain ~~connection~~certain ~~with the going private transaction and the associated~~ financial covenants ~~that step down over time~~, weincluding ~~believe~~financial ~~that~~covenants ~~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~~limit ~~less~~certain ~~favorable than anticipated, lower realized commodity prices, operational~~capital ~~problems~~expenditures orin ~~other~~some ~~factors, or if our borrowing needs are greater than we expect~~circumstances. ~~See also Note 1 to the accompanying financial statements.~~ The ~~agreement~~amount ~~requires~~and usnature ~~to reduce amounts outstanding under the facility with the proceeds~~ of ~~certain~~our ~~transactions~~future orcapital ~~events,~~expenditures ~~including~~will ~~sales~~be ofaffected ~~assets, in certain circumstances. The revolving credit facility is secured~~ by athese ~~first priority lien on substantially all of our assets~~covenants.

~~Loans~~In ~~under~~addition, ~~the~~Venoco ~~revolving~~is ~~credit~~subject ~~facility~~to ~~designated~~various aslegal ~~"Base~~and ~~Rate~~contractual ~~Loans"~~limitations ~~bear~~on ~~interest~~its atability ato ~~floating~~pay ~~rate~~dividends ~~equal~~or otherwise make distributions to ~~(i) the~~DPC, ~~greater~~and ofDPC ~~(x) the~~will ~~administrative~~be ~~agent~~able to pay interest on its 12.25% / 13.00% senior PIK toggle notes in cash only if it receives cash dividends or distributions from Venoco. The principal contractual limits on Venoco's ability to pay dividends or make ~~announced~~distributions ~~base~~to ~~rate,~~DPC ~~(y)~~ are the ~~federal~~covenants ~~funds~~regarding ~~rate~~restricted ~~plus~~payments 0in the indenture governing Venoco's 8.50875% senior notes and ~~(z)~~the agreement governing its revolving credit facility. As of September 30, 2013, Venoco would have been permitted to pay aggregate cash dividends to DPC of approximately $185 million under the ~~one-month~~indenture ~~LIBOR~~governing ~~plus~~the 18.0875% senior notes, ~~plus~~without violating ~~(ii)~~ the restricted payment covenant in the indenture. This amount is only an ~~applicable~~estimate ~~margin~~and ~~ranging~~the actual amount payable by Venoco from ~~1.25%~~time to ~~2.00%~~time pursuant to the indenture, ~~based~~if ~~upon utilization.~~any, ~~Loans~~may ~~designated~~be substantially asdifferent. ~~"LIBO~~Under ~~Rate~~the ~~Loans"~~current ~~under~~terms of the revolving credit ~~facility~~agreement, ~~bear~~Venoco ~~interest~~is atpermitted ~~(i) LIBOR~~to ~~plus~~pay ~~(ii)~~dividends in certain circumstances up to a maximum amount of $35 anmillion ~~applicable~~in ~~margin~~a four-quarter ~~ranging~~period ~~from~~on 2a rolling basis.~~25%~~ The amount of dividends permitted under Venoco's debt agreements will vary over time, in part due to ~~3.00%~~factors such as our operating performance, ~~based~~commodity ~~upon~~prices ~~utilization.~~and ~~The~~general ~~applicable~~economic ~~margin~~factors, ~~for~~many ~~both~~of ~~Base~~which ~~Rate~~are ~~Loans~~outside of our control, and ~~LIBO~~they ~~Rate~~may ~~Loans~~vary ~~will~~further beas ~~increased~~a byresult ~~0.50%~~of inamendments to the ~~event~~agreements that ~~our~~we ~~debt~~enter tointo ~~EBITDA~~or ~~ratio~~the ~~exceeds~~terms ~~3.75~~of tonew 1agreements.00 Therefore, onwe ~~the~~cannot ~~last~~assure ~~day~~you ofthat ~~each~~DPC ~~of the~~will ~~two~~be ~~fiscal~~able ~~quarters~~to ~~most~~pay ~~recently~~interest ~~ended~~on the notes in cash. AIn ~~commitment~~September ~~fee~~2013, Venoco paid a dividend of 0$15.~~50%~~8 million ~~per~~to ~~annum~~DPC; isDPC ~~payable~~expects ~~with~~to ~~respect~~use these funds to make ~~unused~~the ~~borrowing~~first ~~availability~~interest ~~under~~payment ~~the~~on ~~facility~~its notes in February 2014.

The ~~revolving~~following ~~credit~~is ~~facility has~~ a ~~total~~summary ~~capacity~~ of ~~$500.0 million, but is limited by~~ the ~~lesser~~terms of ~~commitments~~our ~~from~~significant ~~participating~~debt ~~lenders~~agreements as of ~~$268.0~~September ~~million and our borrowing base which~~30, ~~as discussed above~~2013, isconsisting ~~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~~Venoco's ~~lenders.~~revolving 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, orVenoco's a8.875% ~~reduction~~senior ~~in the~~notes ~~borrowing~~and ~~base,~~DPC's ~~would adversely affect our liquidity~~12. ~~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~~13.~~6 million~~00% ofsenior ~~outstanding~~PIK ~~letters~~toggle ~~of credit~~notes.

~~Second~~Revolving ~~Lien~~Credit ~~Term Loan~~Facility. In ~~connection~~October ~~with~~2012, ~~the~~Venoco ~~going~~entered ~~private~~into ~~transaction,~~a wefifth ~~entered~~amended ~~into~~and restated credit agreement governing its 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 ~~$315~~restrict Venoco's ability to incur indebtedness and require us to maintain specified ratios of current assets to current liabilities, debt to EBITDA and interest coverage.~~0 million~~ ~~senior~~The ~~secured~~agreement ~~second~~also ~~lien~~limits the ~~term~~amount ~~loan~~of exploratory capital spending we can incur on our onshore Monterey program if Venoco's 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 ~~October~~the ~~2012~~agreement) is 1.75 to 1.00. In March 2013, Venoco entered into an amendment to the ~~first~~revolving ~~quarter~~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, westepping ~~applied~~down ~~Sacramento~~over time ~~Basin~~to ~~sales~~4.00 ~~proceeds~~to 1.00 by September 30, 2014. As amended, the agreement also requires that Venoco's ratio of secured debt (as defined) to ~~prepay~~EBITDA ~~$214~~not exceed 2.700 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 into $270 million. Venoco borrowed an additional ~~principal~~$107 million under the facility contemporaneously with entering into the amendment, and used those funds to repay all amounts outstanding under ~~the~~its second lien term loan ~~and $6~~facility.~~4 million~~ As a result of the additional debt incurred in ~~prepayment~~connection ~~penalties,~~with the going private transaction and the associated financial covenants that step down over time, we ~~then~~believe ~~used~~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

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~~$107.0 million~~financial ofstatements. ~~additional~~The ~~borrowings~~agreement ~~under~~requires ~~the~~us ~~revolving credit facility~~ to ~~repay~~reduce ~~all remaining~~ amounts outstanding under the ~~loan~~facility ~~and~~with anthe ~~additional~~proceeds ~~$3.0 million~~of ~~in prepayment penalties. The agreement contained~~ certain ~~customary~~transactions ~~covenants~~or events, including ~~covenants~~sales ~~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~~assets, ~~interest~~in ~~coverage and collateral coverage~~certain circumstances. The ~~term~~revolving ~~loan~~credit facility ~~was~~is secured by a ~~second~~first priority lien on substantially all of our assets.

~~Loans~~In ~~made~~August ~~under~~2013, ~~the~~Venoco ~~second~~entered ~~lien~~into ~~term~~an ~~loan~~amendment ~~facility~~to ~~were~~its ~~designated,~~revolving atcredit ~~our~~facility ~~option,~~to asincrease ~~either~~its ~~"Base~~ability ~~Rate~~to ~~Loans"~~pay ordividends ~~"LIBO~~to ~~Rate Loans~~DPC." ~~Loans~~The ~~designated~~amendment asgenerally ~~Base~~permits ~~Rate~~Venoco, ~~Loans~~subject ~~bore~~to certain ~~interest~~conditions, ~~at a~~to ~~floating~~pay ~~rate~~cash ~~equal~~dividends to ~~(i) the~~DPC ~~greater~~up ofto ~~(x) the~~a ~~administrative~~maximum ~~agent's~~amount ~~announced~~of ~~prime rate, (y)~~$35 ~~the~~million ~~federal~~in ~~funds~~a ~~rate plus 0.50% and (z) the one~~four-~~month~~quarter ~~LIBOR~~period ~~plus 1.0%,~~on ~~plus~~a ~~(ii) 6.00%.~~rolling ~~Loans designated as LIBO Rate Loans bore interest at LIBOR plus 7~~basis.~~00%.~~ ~~Per the second lien term loan agreement, LIBOR was to be not less than 1.50%.~~

~~8.875%~~ Loans under ~~Senior~~the ~~Notes. In~~revolving ~~February~~credit ~~2011,~~facility wedesignated ~~issued~~as ~~$500 million~~"Base inRate ~~8.875%~~Loans" ~~senior~~bear ~~unsecured~~interest ~~notes~~at ~~due~~a infloating ~~February~~rate ~~2019~~equal atto ~~par. Concurrently with~~ (i) the ~~sale~~greater of (x) the ~~8.875%~~administrative ~~senior~~agent's announced ~~notes~~base rate, we(y) the ~~repaid~~federal infunds ~~full~~rate ~~the~~plus ~~outstanding~~0.50% ~~principal~~and ~~balance~~(z) the ofone-month ~~$455.3 million~~LIBOR onplus ~~the~~1.0%, ~~second~~plus ~~lien~~(ii) an ~~term~~applicable ~~loan~~margin ~~then~~ranging infrom ~~place~~1.25% ~~The~~to 82.~~875~~00%, ~~senior~~based ~~notes pay interest~~upon ~~semi-annually~~utilization. inLoans ~~arrears~~designated onas ~~February 15~~"LIBO ~~and~~Rate ~~August 15~~Loans" ofunder ~~each~~the ~~year.~~revolving Wecredit ~~may~~facility ~~redeem~~bear ~~the~~interest ~~notes~~at ~~prior~~(i) LIBOR toplus ~~February~~(ii) ~~15,~~an ~~2015~~applicable atmargin aranging ~~"make~~from ~~whole~~2.25% ~~premium"~~to ~~defined~~3.00%, inbased ~~the indenture.~~upon ~~Beginning~~utilization. ~~February 15,~~The ~~2015,~~applicable wemargin ~~may~~for ~~redeem~~both ~~the~~Base ~~notes~~Rate atLoans aand ~~redemption~~LIBO ~~price~~Rate ofLoans ~~104~~will be increased by 0.~~438~~50% ofin the ~~principal~~event ~~amount~~that ~~and~~Venoco's ~~declining~~debt to ~~100%~~EBITDA byratio ~~February 15,~~exceeds ~~2017~~3.75 ~~The~~to 81.~~875%~~00 ~~senior~~on ~~notes~~the ~~are~~last day of each ~~senior~~of ~~unsecured~~the ~~obligations~~two ~~and~~fiscal ~~contain~~quarters ~~operational~~most ~~covenants~~recently ~~that,~~ended. ~~among~~A ~~other~~commitment ~~things,~~fee ~~limit~~of ~~our~~0.50% ~~ability~~per toannum ~~make~~is ~~investments,~~payable ~~incur~~with ~~additional~~respect ~~indebtedness~~to orunused ~~create~~borrowing ~~liens~~availability onunder ~~our~~the ~~assets~~facility.

~~11.50%~~ The revolving ~~Senior~~credit ~~Notes. In~~facility ~~October~~has ~~2009,~~a wetotal ~~issued~~capacity of $~~150~~500.0 million, ofbut ~~11.50%~~is ~~senior~~limited ~~unsecured~~by ~~notes~~the ~~due~~lesser inof ~~October~~commitments ~~2017~~from atparticipating alenders ~~price~~ of 95 $268.~~03%~~0 million ofand the ~~par.~~borrowing ~~The~~base ~~notes~~which, ~~pay~~as ~~interest~~discussed ~~semi-annually~~above, inis ~~arrears~~currently onestablished ~~April~~at $270.0 1million. ~~and~~The ~~October 1~~borrowing ofbase is subject to redetermination twice each year., Weand may ~~redeem~~be redetermined at other times at our request or at the ~~notes~~request ~~prior~~of tothe ~~October 1,~~lenders. ~~2013~~Lending commitments under the facility have been allocated at various percentages to a ~~"make-whole~~syndicate ~~price"~~of ~~defined~~ten banks. Certain of the institutions included in the ~~indenture.~~syndicate ~~Beginning~~have ~~October 1,~~received ~~2013,~~support wefrom ~~may~~governmental ~~redeem~~agencies in connection with events in the ~~notes~~credit atmarkets. aA ~~redemption~~failure ~~price~~of ~~equal~~any members of the syndicate to ~~105.75%~~fund ofunder the ~~principal~~facility, ~~amount~~or ~~and~~a ~~declining~~reduction toin ~~100%~~the borrowing bybase, ~~October~~would adversely affect our liquidity. As of November 112, ~~2016~~2013, we had $213.0 million ~~The~~outstanding ~~indenture governing~~under the ~~notes~~facility ~~contains~~at ~~operational~~an ~~covenants~~average ~~that,~~interest ~~among~~rate ~~other~~of ~~things,~~3.63% ~~limit~~and $51.4 million ~~our~~in ~~ability~~available toborrowing ~~make investments~~capacity, ~~incur~~net ~~additional~~of ~~indebtedness~~the oroutstanding ~~create~~balance ~~liens~~and on$3.6 million ~~our~~of ~~assets~~outstanding letters of credit.

~~Because we~~Venoco ~~must~~8.875% ~~dedicate~~Senior aNotes. In ~~substantial~~February ~~portion~~2011, ofVenoco ~~our~~issued ~~cash~~$500 million ~~flow~~in ~~from~~8.875% ~~operations~~senior tounsecured ~~the~~notes ~~payment of amounts~~ due ~~under~~in ~~our~~February ~~debt~~2019 ~~agreements, that portion of our cash flow is not available~~at ~~for other purposes~~par. Concurrently ~~Our~~with ~~ability~~the tosale ~~make~~of ~~scheduled~~the ~~interest~~8.875% ~~payments~~senior ~~on our indebtedness~~notes, ~~maintain~~Venoco ~~compliance~~repaid ~~with the covenants~~ in ~~our~~full ~~debt~~the ~~agreements~~outstanding ~~and~~principal ~~pursue~~balance ~~our~~of ~~capital~~$455.3 million ~~expenditure plan will depend to a significant extent~~ on ~~our~~the ~~financial~~second ~~and~~lien ~~operating~~term ~~performance,~~loan ~~which~~then isin ~~subject~~place. toThe ~~prevailing economic conditions, commodity prices and a variety of other factors~~8.875% ~~If our cash flow and~~senior ~~other~~notes ~~capital~~pay ~~resources~~interest ~~are~~semi-annually ~~insufficient~~in toarrears ~~fund~~on ~~our~~February 15 ~~debt service obligations~~ and ~~our~~August 15 ~~capital~~of ~~expenditure~~each ~~budget~~year. ~~while~~Venoco ~~also~~may ~~allowing~~redeem usthe tonotes ~~maintain~~prior ~~compliance with our debt agreements, we may be forced~~ to ~~reduce or delay scheduled capital projects~~February 15, ~~sell~~2015 ~~material assets or operations and/or seek additional capital. Needed capital may not be available on acceptable terms or~~ at ~~all.~~a ~~Our~~"make ~~ability to~~whole ~~raise~~premium" ~~funds~~defined ~~through~~ in the ~~incurrence of additional indebtedness and certain other means is limited by covenants in our debt agreements~~indenture. InBeginning ~~addition~~February 15, ~~pursuant to mandatory prepayment provisions in our debt agreements~~2015, ~~our~~Venoco ~~ability~~may toredeem ~~respond to a shortfall in our expected liquidity by selling assets or incurring additional indebtedness would be limited by provisions in~~ the ~~agreements~~notes ~~that~~at ~~require~~a ~~us to~~redemption ~~use~~price ~~some~~of or104.438% ~~all~~ of the ~~proceeds~~principal ofamount ~~such~~and ~~transactions~~declining to ~~reduce~~100% ~~amounts~~by ~~outstanding~~February 15, ~~under~~2017. ~~the~~The ~~agreements in some circumstances~~8.875% senior Ifnotes we are ~~unable~~senior tounsecured ~~obtain~~obligations ~~funds when needed~~ and oncontain ~~acceptable~~operational ~~terms, we~~covenants ~~may not be able to complete acquisitions~~ that, ~~may~~among beother ~~favorable to us~~things, ~~meet~~limit ~~our~~Venoco's ~~debt~~ability ~~obligations or finance the capital expenditures necessary~~ to ~~replace~~make ~~our~~investments, ~~reserves.~~incur ~~The~~ additional indebtedness ~~we incurred~~or increate ~~connection~~liens ~~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~~its toassets. ~~replace our reserves and maintain our production may be adversely affected by capital constraints and the financial~~

44 DPC 12.25% / 13.00% Senior PIK Toggle Notes. In August 2013, DPC issued $255 million principal amount of 12.25% / 13.00% senior PIK toggle notes due 2018 at 97.304% of par. Interest on the notes is payable on February 15 and August 15 of each year, commencing February 15, 2014. The initial interest payment on the notes will be payable in cash. For each interest period thereafter (other than for the final interest period ending at the stated maturity, which will be paid in cash), DPC will, in certain circumstances, be permitted to pay interest on the notes by increasing the principal amount of the notes or issuing new notes (collectively, "PIK interest"). Cash interest on the notes will accrue at the rate of 12.25% per annum. PIK interest on the notes will accrue at the rate of 13.00% per annum until the next payment of cash interest. The notes are not currently guaranteed by any of DPC's subsidiaries. DPC may redeem the notes, in whole or in part, at any time prior to August 15, 2015, at a "make-whole" redemption price described in the indenture. DPC may also redeem all or any part of

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~~covenants~~the ~~under~~notes ~~our~~on ~~debt~~and ~~agreements~~after ~~and~~August 15, ~~that~~2015 weat ~~may~~a beredemption ~~more~~price ~~vulnerable~~of 106.125% of the principal amount and declining to ~~adverse~~100% ~~changes~~by inAugust 15, ~~commodity~~2017. ~~prices~~The notes are senior unsecured obligations and contain operational covenants that, among other ~~economic~~things, ~~conditions~~limit our ability to make investments, incur additional indebtedness, issue preferred stock, pay dividends, repurchase stock, create liens or sell 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.

Off-Balance Sheet Arrangements

At ~~June~~September 30, 2013, we had no existing off-balance sheet arrangements, as defined under SEC rules, that have or are ~~reasonably~~ 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.

Adjusted Consolidated Net Tangible Assets

As of September 30, 2013, DPC's "Adjusted Consolidated Net Tangible Assets," as that term is defined in the indenture governing its 12.25% / 13.00% senior PIK toggle notes, was $1.5 billion.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

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

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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 Transactions

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~~September 30, 2013, we had entered into various swap, collar and option agreements related to our oil production. ~~The~~ 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~~ provide for monthly settlement based on the differential between the agreement price and the actual Brent price.

	Oil (Brent)
	Barrels/day		Weighted Avg. Prices per Bbl
July 1 - December 31, 2013:
October 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
Swaps		1,000	$	106.00
Collars		4,100		$90.00/$98.59
Puts		575	$	90.00
January 1 - December 31, 2015:
Collars		3,675	$	$90.00/$98.95

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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.

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Portfolio of Derivative Transactions

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

Oil

Type of Contract	Counterparty	Basis		Strike Price ($/Bbl)		Term
Collar	Bank of Nova Scotia	Brent	700	$	$90.00/$122.70	Oct 1, 13—Dec 31, 13	~~Jul 1, 13 - Dec 31, 13~~
Swap	Bank of Nova Scotia	Brent	675	$	106.50	Oct 1, 13—Dec 31, 13	~~Jul 1, 13 - Dec 31, 13~~
Swap	Citibank N.A.	Brent	675	$	106.53	Oct 1, 13—Dec 31, 13	~~Jul 1, 13 - Dec 31, 13~~
Put	Bank of America	Brent	750		90.00	Oct 1, 13—Dec 31, 13	~~Jul 1, 13 - Dec 31, 13~~
Collar	Key Bank	Brent	225	$	$90.00/$97.00	Oct 1, 13—Dec 31, 14	~~Jul 1, 13 - Dec 31, 14~~
Collar	Key Bank	Brent	200	$	$90.00/$93.75	Jan 1, 14—Dec 31, 14	~~Jan 1, 14 - Dec 31, 14~~
Put	Citibank N.A.	Brent	575	$	90.00	Jan 1, 14—Dec 31, 14	~~Jan 1, 14 - Dec 31, 14~~
Collar	Credit Suisse	Brent	1,000	$	90.00/$98.00		Jul 1, 13 - Dec 31, 15
Swap	Bank of America	Brent	1,000	$	106.00	Jan 1, 14—Dec 31, 14
Collar	~~Bank~~Credit ~~of America~~Suisse	Brent	1,000	$	$90.00/$~~101~~98.2500	Oct 1, 13—Dec 31, 15	~~Jul 1, 13 - Dec 31, 15~~
Collar	Bank of ~~Nova Scotia~~America	Brent	1,~~675~~000	$	$90.00/$98101.1525	Oct 1, 13—Dec 31, 15	~~Jul 1, 13 - Dec 31, 15~~
Collar	Bank of Nova Scotia	Brent	1,675		$90.00/$98.15	Oct 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~~Venoco's 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~~Venoco's 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~~Venoco's revolving credit facility and derivative contracts contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations.

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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.

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the determination date. Changes in the fair value of derivatives are recorded in commodity derivative (gains) losses on the consolidated statement of operations. As of September 30, 2013, the fair value of our commodity derivatives was a net liability of $12.8 million.

Interest Rate Risk

We are subject to interest rate risk with respect to amounts borrowed from time to time under ~~our~~Venoco's revolving credit facility ~~because~~ 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 $12.81 million on our variable rate borrowings of $~~183.0~~208 million as of ~~June~~September 30, 2013.

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

ITEM 4. Controls and Procedures

Disclosure Controls and Procedures

Our management, with the participation of Edward O'Donnell, ~~our~~Venoco's Chief Executive Officer, Timothy Marquez, DPC's Chief Executive Officer, and Timothy Ficker, our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of ~~June~~September 30, 2013. Based on the evaluation, those officers ~~believe~~ believe that:

•: our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms; and
•: our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 was accumulated and communicated to our management, including our Chief Executive Officers and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Internal Control Over Financial Reporting

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

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PART II—OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

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

Item 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in "Risk Factors" in ~~our~~Venoco's 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~~ this report and in ~~our~~Venoco's 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. Because DPC is a holding company and has no assets other than 100% of the common stock of Venoco and any cash on hand, the risks described in Venoco's Annual Report on Form 10-K for the year ended December 31, 2012 are applicable to DPC as well.

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

Not Applicable

Item 3. DEFAULTS UPON SENIOR SECURITIES

Not Applicable

Item 4. MINE SAFETY DISCLOSURES

Not Applicable

Item 5. OTHER INFORMATION

Not Applicable

Item 6. EXHIBITS

Exhibit Number		Exhibit	~~Exhibit~~
31.1	~~31.1~~	Certification of the Chief Executive Officer of Venoco, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	~~Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.~~
31.2	~~31.2~~	Certification of the Chief Financial Officer of Venoco, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	~~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.
31.3		Certification of the Chief Executive Officer of Denver Parent Corporation Pursuant to Section 302 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.
31.4		Certification of the Chief Financial Officer of Denver Parent Corporation Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of the Chief Executive Officer and the Chief Financial Officer of Venoco, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of the Chief Executive Officer and the Chief Financial Officer of Denver Parent Corporation Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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Exhibit Number		Exhibit

101		The following financial information from the quarterly report on Form 10-Q of Venoco, Inc. and Denver Parent Corporation for the quarter ended September 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.

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SIGNATURES

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

~~August~~November 113, 2013


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

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

November 13, 2013


DENVER PARENT CORPORATION
By:	/s/ TIMOTHY M. MARQUEZ
	Name:	Timothy M. Marquez
	Title:	Chief Executive Officer
By:	/s/ TIMOTHY A. FICKER
	Name:	Timothy A. Ficker
	Title:	Chief Financial Officer

Filing Compare · Venoco, Inc.