UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-‑Q

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

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30,2015
Or
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2015

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

Commission File Numbers:

Denver Parent Corporation 333-‑191602

Venoco, Inc. 001-33152

Denver Parent Corporation

Venoco, Inc.

Delaware Delaware (State or other jurisdiction of incorporation or organization)		44-0821005 77-0323555 (I.R.S. Employer Identification Number)
DelawareDelaware(State or other jurisdiction ofincorporation or organization)	46-082100577-0323555(I.R.S. EmployerIdentification Number)
370 17th Street, Suite 3900 Denver, Colorado (Address of principal executive offices)		80202-1370 (Zip Code)
370 17th Street, Suite 3900Denver, Colorado(Address of principal executive offices)	80202‑1370(Zip Code)

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

N/A

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

Indicate by check mark whether the registrant (1) has filed all reports required by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Venoco, Inc. YES o☐ NO x☒ Denver Parent Corporation YES o☐ NO x☒

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 x☒ NO o☐ Denver Parent Corporation YES x☒ 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 x ☒(Do not check if aasmaller ~~smaller~~ reporting company) Smaller reporting company o☐ Denver Parent Corporation Large accelerated filer o☐ Accelerated filer o☐ Non-‑accelerated filer x ☒(Do not check if aasmaller ~~smaller~~ reporting company) Smaller reporting company o☐

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

Venoco, Inc. YES o☐ NO x☒ Denver Parent Corporation YES o☐ NO x☒

As of ~~August 19~~November 12, 2015, there were 30,297,459 shares of common stock of 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, Venoco’s future ability to pay cash dividends and Venoco’s and Denver Parent Corporation’s compliance with obligations under their respective 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 in the Venoco, Inc. / Denver Parent Corporation Annual Report on Form 10-K for the year ended December 31, 2014. 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. 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 the Venoco, Inc. / Denver Parent Corporation Annual Report on Form 10-K for the year ended December 31, 2014 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 oil and natural gas reserves;

risks arising out of our hedging transactions;

· our inability to access oil and natural gas markets due to operational impediments, including as a result of the shutdown of the pipeline that transports production from Platform Holly;

uninsured or underinsured losses in, or operational problems affecting, our operations;

variable nature and uncertainty 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, which 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;

challenges and difficulties in managing expenses, including expenses associated with asset retirement obligations;

a lack of available capital and financing;

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

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

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

the effect of any business combination, joint venture or other significant transaction we may pursue or have pursued, or the costs of litigation related thereto, and purchase price or other adjustments in connection with such transactions that may be unfavorable to us;

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· the effect of any business combination, joint venture or other significant transaction we may pursue or have pursued, 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, from regulations relating to greenhouse gas emissions and possible regulatory responses to the spill that resulted in the shutdown of the pipeline that transports Platform Holly production;

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.

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 the Financial Statements section.

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 in which 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 ~~June~~ September 30, 2015

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PART I.	FINANCIAL INFORMATION	4
Item 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets at December 31, 2014 and June 30, 2015	4
	Condensed Consolidated Balance Sheets at December 31, 2014 and September 30,2015	4
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2014 and the Three and Six Months Ended June 30, 2015	5
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30,2014 and the Three and Nine Months Ended September 30,2015	5
	Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Six Months Ended June 30, 2015	6
	Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Nine Months Ended September 30,2015	6
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2014 and the Six Months Ended June 30, 2015	7
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30,2014 and the Nine Months Ended September 30,2015	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2527
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	3435
Item 4.	Controls and Procedures	3537
PART II.	OTHER INFORMATION	3638
Item 1.	Legal Proceedings	3638
Item 1A.	Risk Factors	3638
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3638
Item 3.	Defaults upon Senior Securities	3638
Item 4.	Mine Safety Disclosures	3638
Item 5.	Other Information	3638
Item 6.	Exhibits	3639
Signatures		3740

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PART I—FINANCIAL INFORMATION

~~VENOCO, INC~~ Item 1. ~~AND~~Financial ~~SUBSIDIARIES~~Statements ~~AND DENVER PARENT~~(Unaudited)

~~CORPORATION~~ VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENTCORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(In thousands, except share amounts)

	Venoco, Inc.						Denver Parent Corporation
							Denver Parent
	December 31, 2014			June 30, 2015			December 31, 2014			June 30, 2015
	Venoco, Inc.						Corporation
	December 31,			September 30,			December 31,			September 30,
	2014			2015			2014			2015
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	15,455		$	~~114~~94,~~009~~708		$	15,656		$	~~114~~94,~~141~~840
Restricted funds	—	—		~~79,595~~	79,588		—	—		~~79,595~~	79,588
Accounts receivable	~~14,912~~	14,912		~~9,039~~	9,979		~~14,912~~	14,912		~~9,039~~	9,979
Inventories	~~3,370~~	3,370		~~3,299~~	3,329		~~3,370~~	3,370		~~3,299~~	3,329
Other current assets	~~4,715~~	4,715		~~2,272~~	4,088		~~4,721~~	4,721		~~2,275~~	4,089
Commodity derivatives	~~48,298~~	48,298		~~30,545~~	37,240		~~48,298~~	48,298		~~30,545~~	37,240
Total current assets	~~86,750~~	86,750		~~238,759~~	228,932		~~86,957~~	86,957		~~238,894~~	229,065
PROPERTY, PLANT AND EQUIPMENT, AT COST:
Oil and gas properties, full cost method of accounting
Proved	~~1,866,415~~	1,866,415		~~1,874,582~~	1,888,417		~~1,866,415~~	1,866,415		~~1,874,582~~	1,888,417
Unproved	~~8,360~~	8,360		~~8,530~~	8,536		~~8,360~~	8,360		~~8,530~~	8,536
Accumulated depletion	~~(1,400,738~~	(1,400,738)	)	~~(1,561,934~~	(1,757,603)	)	~~(1,400,738~~	(1,400,738)	)	~~(1,561,934~~	(1,757,603)	)
Net oil and gas properties	~~474,037~~	474,037		~~321,178~~	139,350		~~474,037~~	474,037		~~321,178~~	139,350
Other property and equipment, net of accumulated depreciation and amortization of $14,566 and $15,454 at December 31, 2014 and June 30, 2015, respectively	14,477			13,707			14,477			13,707
Other property and equipment, net of accumulated depreciation and amortization of $14,566 and $14,787 at December 31, 2014 and September 30, 2015, respectively		14,477			13,366			14,477			13,366
Net property, plant and equipment	~~488,514~~	488,514		~~334,885~~	152,716		~~488,514~~	488,514		~~334,885~~	152,716
OTHER ASSETS:
Commodity derivatives	~~29,793~~	29,793		~~8,653~~	6,558		~~29,793~~	29,793		~~8,653~~	6,558
Deferred loan costs	~~7,128~~	7,128		~~12,313~~	11,353		~~11,614~~	11,614		~~16,265~~	14,625
Other	~~4,069~~	4,069		~~4,279~~	4,277		~~4,069~~	4,069		~~4,279~~	4,277
Total other assets	~~40,990~~	40,990		~~25,245~~	22,188		~~45,476~~	45,476		~~29,197~~	25,460
TOTAL ASSETS	$	616,254		$	~~598~~403,~~889~~836		$	620,947		$	~~602~~407,~~976~~241
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	20,535		$	1524,~~019~~188		$	20,535		$	1524,~~019~~188
Interest payable	~~17,329~~	17,329		~~15,926~~	8,814		~~17,329~~	17,329		~~15,926~~	8,814
Share-based compensation	~~2,236~~	2,236		~~176~~	191		~~2,236~~	2,236		~~176~~	191
Total current liabilities	~~40,100~~	40,100		~~31,121~~	33,193		~~40,100~~	40,100		~~31,121~~	33,193
LONG-TERM DEBT	~~565,000~~	565,000		~~685,346~~	691,389		~~840,065~~	840,065		~~979,347~~	995,565
ASSET RETIREMENT OBLIGATIONS	~~30,351~~	30,351		~~33,150~~	33,076		~~30,351~~	30,351		~~33,150~~	33,076
SHARE-BASED COMPENSATION	~~648~~	648		~~235~~	463		~~648~~	648		~~235~~	463
Total liabilities	~~636,099~~	636,099		~~749,852~~	758,121		~~911,164~~	911,164		~~1,043,853~~	1,062,297
COMMITMENTS AND CONTINGENCIES STOCKHOLDERS’ EQUITY(DEFICIT):
COMMITMENTS AND CONTINGENCIES (note 7)
Common stock, $.01 par value (200,000,000 shares authorized for Venoco and 100,000,000 authorized for DPC; 29,936,378 Venoco shares issued and outstanding at December 31, 2014 and June 30, 2015; 30,297,459 DPC shares issued and outstanding at December 31, 2014 and June 30, 2015)	299			299			303			303
STOCKHOLDERS’ EQUITY (DEFICIT):
Additional paid-in capital	285,120			285,616			73,902			74,398
Common stock, $.01 par value (200,000,000 shares authorized for Venoco and 100,000,000 shares for DPC; 29,936,378 Venoco shares issued and outstanding at December 31, 2014 and September 30, 2015; 30,297,459 DPC shares issued and outstanding at December 31, 2014 and September 30, 2015)		299			299			303			303
Retained earnings (accumulated deficit)	(305,264		)	(436,878		)	(364,422		)	(515,578		)
Additional paid-in capital		285,120			285,616			73,902			74,398
Total stockholders’ equity(deficit)	(19,845		)	(150,963		)	(290,217		)	(440,877		)
Retained earnings (accumulated deficit)		(305,264)			(640,200)			(364,422)			(729,757)
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY(DEFICIT)	$	616,254		$	598,889		$	620,947		$	602,976
Total stockholders’ equity (deficit)		(19,845)			(354,285)			(290,217)			(655,056)
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	$	616,254		$	403,836		$	620,947		$	407,241

See notes to condensed consolidated financial statements.

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VENOCO, INC. AND SUBSIDIARIES AND DENVER ~~PARENT~~PARENTCORPORATION AND SUBSIDIARIES

CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(In thousands)

	Venoco, Inc.											Denver Parent Corporation
	Three Months Ended June 30,						Six Months Ended June 30,					Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended						Nine Months Ended					Three Months Ended						Nine months ended
	September 30,						September 30,					September 30,						September 30,
	2014			2015			2014		2015			2014			2015			2014			2015
REVENUES:
Oil and natural gas sales	$	6657,~~563~~242		$	1910,~~317~~646		$	~~129~~186,~~101~~343	$	3949,~~066~~712		$	6657,~~563~~242		$	1910,~~317~~646		$	~~129~~186,~~101~~343		$	3949,~~066~~712
Other	~~476~~	609		~~553~~	508		~~935~~	1,544	~~1,222~~	1,730		~~476~~	609		~~553~~	508		~~935~~	1,544		~~1,222~~	1,730
Total revenues	~~67,039~~	57,851		~~19,870~~	11,154		~~130,036~~	187,887	~~40,288~~	51,442		~~67,039~~	57,851		~~19,870~~	11,154		~~130,036~~	187,887		~~40,288~~	51,442
EXPENSES:
Lease operating expense	~~18,185~~	18,225		~~13,206~~	12,955		~~37,653~~	55,878	~~28,138~~	41,093		~~18,185~~	18,225		~~13,206~~	12,955		~~37,653~~	55,878		~~28,138~~	41,093
Property and production taxes	2,270			2,027			4,006		4,159			2,270			2,027			4,006			4,159
Production and property taxes		2,124			747			6,130		4,906			2,124			747			6,130			4,906
Transportation expense	49	51		46	54		~~106~~	157	93	147		49	51		46	54		~~106~~	157		93	147
Depletion, depreciation and amortization	~~11,794~~	11,759		~~7,234~~	4,260		~~22,970~~	34,729	~~16,055~~	20,315		~~11,794~~	11,759		~~7,234~~	4,260		~~22,970~~	34,729		~~16,055~~	20,315
Impairment of oil and natural gas properties	817			146,030			817		146,030			817			146,030			817			146,030
Impairment		—			191,800			817		337,830			—			191,800			817			337,830
Accretion of asset retirement obligations	~~556~~	629		~~514~~	525		~~1,223~~	1,852	~~1,011~~	1,536		~~556~~	629		~~514~~	525		~~1,223~~	1,852		~~1,011~~	1,536
General and administrative, net of amounts capitalized	~~8,990~~	1,352		~~7,037~~	5,890		~~17,652~~	19,004	~~13,707~~	19,597		~~9,075~~	1,403		~~7,038~~	5,890		~~17,991~~	19,394		~~13,776~~	19,666
Total expenses	~~42,661~~	34,140		~~176,094~~	216,231		~~84,427~~	118,567	~~209,193~~	425,424		~~42,746~~	34,191		~~176,095~~	216,231		~~84,766~~	118,957		~~209,262~~	425,493
Income from operations	24,378			(156,224		)	45,609		(168,905		)	24,293			(156,225		)	45,270			(168,974		)
Income (loss) from operations		23,711			(205,077)			69,320		(373,982)			23,660			(205,077)			68,930			(374,051)
FINANCING COSTS AND OTHER:
Interest expense, net	~~13,351~~	13,635		~~19,926~~	18,711		~~26,291~~	39,926	~~31,337~~	50,048		~~21,766~~	22,613		~~29,590~~	28,885		~~42,889~~	65,502		~~50,272~~	79,158
Amortization of deferred loan costs	~~863~~	887		~~1,480~~	973		~~1,696~~	2,583	~~2,087~~	3,060		~~1,110~~	1,151		~~1,754~~	1,656		~~2,187~~	3,338		~~2,625~~	4,280
Loss(gain) on extinguishment of debt	—			(67,515		)	—		(67,515		)	—			(67,515		)	—			(67,515		)
Loss (gain) on extinguishment of debt		—			—			—		(67,515)			—			—			—			(67,515)
Commodity derivative losses (gains), net	~~18,910~~	(30,336)		~~9,705~~	(21,439)		~~16,815~~	(13,521)	~~(3,200~~	(24,639)	)	~~18,910~~	(30,336)		~~9,705~~	(21,439)		~~16,815~~	(13,521)		~~(3,200~~	(24,639)	)
Total financing costs and other	~~33,124~~	(15,814)		~~(36,404~~	(1,755)	)	~~44,802~~	28,988	~~(37,291~~	(39,046)	)	~~41,786~~	(6,572)		~~(26,466~~	9,102	)	~~61,891~~	55,319		~~(17,818~~	(8,716)	)
Income (loss) before income taxes	~~(8,746~~	39,525	)	~~(119,820~~	(203,322)	)	~~807~~	40,332	~~(131,614~~	(334,936)	)	~~(17,493~~	30,232	)	~~(129,759~~	(214,179)	)	~~(16,621~~	13,611	)	~~(151,156~~	(365,335)	)
Income tax provision (benefit)	—			—			—		—			—			—			—			—
INCOME TAX PROVISION (BENEFIT)		—			—			—		—			—			—			—			—
Net income (loss)	$	(839,~~746~~525	)	$	(~~119~~203,~~820~~322)	)	$	~~807~~40,332	$	(~~131~~334,~~614~~936)	)	$	~~(17~~30,~~493~~232	)	$	(~~129~~214,~~759~~179)	)	$	~~(16~~13,~~621~~611	)	$	(~~151~~365,~~156~~335)	)

See notes to condensed consolidated financial statements.

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VENOCO, INC. AND SUBSIDIARIES AND DENVER ~~PARENT~~PARENTCORPORATION AND SUBSIDIARIES

CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(UNAUDITED)

(In thousands)

VENOCO, INC. AND SUBSIDIARIES

	Common Stock			Additional Paid-in		Retained Earnings (Accumulated
						Retained
				Additional		Earnings
	Common Stock			Paid-in		(Accumulated
	Shares	Amount		Capital		Deficit)			Total
BALANCE AT DECEMBER 31, 2014	29,936	$	299	$	285,120	$	(305,264)	)	$	(19,845)	)
Excess of share-based compensation expense recognized over payments made	—	—	—	~~496~~	496	—	—		~~496~~	496
Net income (loss)	—	—	—	—	—	~~(131,614~~	(334,936)	)	~~(131,614~~	(334,936)	)
BALANCE AT JUNE 30, 2015	29,936	$	299	$	285,616	$	(436,878	)	$	(150,963	)
BALANCE AT SEPTEMBER 30, 2015	29,936	$	299	$	285,616	$	(640,200)		$	(354,285)

DENVER PARENT CORPORATION AND SUBSIDIARIES

	Common Stock			Additional Paid-in		Retained Earnings (Accumulated
						Retained
				Additional		Earnings
	Common Stock			Paid-in		(Accumulated
	Shares	Amount		Capital		Deficit)			Total
BALANCE AT DECEMBER 31, 2014	30,297	$	303	$	73,902	$	(364,422)	)	$	(290,217)	)
Excess of share-based compensation expense recognized over payments made	—	—		~~496~~	496	—	—		~~496~~	496
Net income (loss)	—	—	—	—	—	~~(151,156~~	(365,335)	)	~~(151,156~~	(365,335)	)
BALANCE AT JUNE 30, 2015	30,297	$	303	$	74,398	$	(515,578	)	$	(440,877	)
BALANCE AT SEPTEMBER 30, 2015	30,297	$	303	$	74,398	$	(729,757)		$	(655,056)

See notes to condensed consolidated financial statements.

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VENOCO, INC. AND SUBSIDIARIES AND DENVER ~~PARENT~~PARENTCORPORATION AND SUBSIDIARIES

CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In thousands)

	Venoco, Inc.						Denver Parent Corporation
	Six Months Ended June 30,						Six Months Ended June 30,
	Nine Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2015			2014			2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	~~807~~40,332		$	(~~131~~334,~~614~~936)	)	$	~~(16~~13,~~621~~611	)	$	(~~151~~365,~~156~~335)	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	~~22,970~~	34,729		~~16,055~~	20,315		~~22,970~~	34,729		~~16,055~~	20,315
Impairment of oil and natural gas properties	817			146,030			817			146,030
Impairment		817			337,830			817			337,830
Accretion of asset retirement obligations	~~1,223~~	1,852		~~1,011~~	1,536		~~1,223~~	1,852		~~1,011~~	1,536
Share-based compensation	~~1,601~~	1,601		~~496~~	496		~~1,601~~	1,601		~~496~~	496
Interest paid-in-kind	—	—		~~4,460~~	9,105		~~9,264~~	16,916		~~22,791~~	36,892
Amortization of deferred loan costs	~~1,696~~	2,583		~~2,087~~	3,060		~~2,187~~	3,338		~~2,625~~	4,280
Loss (gain) on extinguishment of debt	—	—		~~(67,515~~	(67,515)	)	—	—		~~(67,515~~	(67,515)	)
Amortization of bond discounts and other	—	—		~~1,450~~	2,848		~~530~~	809		~~2,054~~	4,170
Unrealized commodity derivative (gains) losses and amortization of premiums	~~8,760~~	(22,931)		~~38,893~~	34,293		~~8,760~~	(22,931)		~~38,893~~	34,293
Changes in operating assets and liabilities:
Accounts receivable	~~731~~	4,869		~~5,873~~	4,933		~~877~~	5,030		~~5,873~~	4,933
Inventories	~~1,196~~	1,317		71	41		~~1,196~~	1,317		71	41
Other current assets	~~2,366~~	112		~~2,327~~	511		~~2,301~~	40		~~2,327~~	511
Other assets	~~1,766~~	1,815		~~(210~~	(208)	)	~~1,766~~	1,815		~~(210~~	(208)	)
Accounts payable and accrued liabilities	~~3,739~~	(8,128)		~~(5,749~~	(9,335)	)	~~(5,027~~	(19,884)	)	~~(5,749~~	(9,335)	)
Share-based compensation liabilities	~~(16,815~~	(24,348)	)	~~(2,473~~	(2,230)	)	~~(16,815~~	(24,348)	)	~~(2,473~~	(2,230)	)
Net cash provided by (used in) operating activities	30,857			11,192			15,029			11,123
Net premiums paid on derivative contracts		—			—			—			—
Net cash provided by operating activities		34,620			744			14,712			674
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties	~~(52,046~~	(75,836)	)	~~(7,296~~	(16,125)	)	~~(52,046~~	(75,836)	)	~~(7,296~~	(16,125)	)
Acquisitions of oil and natural gas properties	~~(16~~	(38)	)	~~(12~~	(15)	)	~~(16~~	(38)	)	~~(12~~	(15)	)
Expenditures for other property and equipment	~~(295~~	(512)	)	~~(119~~	(169)	)	~~(295~~	(512)	)	~~(119~~	(169)	)
Proceeds provided by sale of oil and natural gas properties	—	—		~~1,811~~	1,846		—	—		~~1,811~~	1,846
Net cash provided by (used in) investing activities	(52,357		)	(5,616		)	(52,357		)	(5,616		)
Net cash (used in) investing activities		(76,386)			(14,463)			(76,386)			(14,463)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	~~132,000~~	182,000		~~340,000~~	340,000		~~132,000~~	182,000		~~340,000~~	340,000
Debt issuance costs	—			(12,427		)	—			(12,427		)
Principal payments on long-term debt		(122,000)			(155,000)			(122,000)			(155,000)
Principal payments on long-term debt	(107,000		)	(155,000		)	(107,000		)	(155,000		)
Payments for deferred loan costs		(371)			(14)			(496)			(14)
Payments for deferred loan costs	(358		)	—			(467		)	—
Debt issuance costs		—			(12,426)			—			(12,426)
Increase in restricted cash	—	—		~~(79,595~~	(79,588)	)	—	—		~~(79,595~~	(79,588)	)
Dividend to Denver Parent Corporation	~~(3,905~~	(3,905)	)	—	—		—	—		—	—
Net cash provided by (used in) financing activities	~~20,737~~	55,724		~~92,978~~	92,972		~~24,533~~	59,504		~~92,978~~	92,972
Net (decrease) increase in cash and cash equivalents	~~(763~~	13,958	)	~~98,554~~	79,253		~~(12,795~~	(2,170)	)	~~98,485~~	79,183
Cash and cash equivalents, beginning of period	~~828~~	828		~~15,455~~	15,455		~~17,336~~	17,336		~~15,656~~	15,656
Cash and cash equivalents, end of period	$	6514,786		$	~~114~~94,~~009~~708		$	415,~~541~~166		$	~~114~~94,~~141~~840
Supplemental Disclosure of Cash Flow Information—
Cash paid for interest	$	2651,~~641~~172		$	2444,~~537~~277		$	4270,~~260~~749		$	2444,~~537~~277
Cash paid (received) for income taxes	$	—		$	—		$	—		$	—
Supplemental Disclosure of Noncash Activities—
(Decrease) increase in accrued capital expenditures	$	2(3,~~766~~823)		$	(16,~~052~~096	)	$	2(3,~~766~~823)		$	(16,~~052~~096	)
Excess of share-based compensation expense recognized over payments made	$	—		$	496		$	—		$	496

See notes to condensed consolidated financial statements.

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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, a Delaware corporation (“DPC”), was formed in January 2012 for the purpose of acquiring all of the outstanding common stock of Venoco, Inc., a Delaware corporation (“Venoco”), in a transaction referred to as the “going private transaction”. The going private transaction was completed in October 2012. DPC has no operations and no material assets other than 100% of the common stock of Venoco. Venoco is engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties with a focus on properties offshore and onshore in California.

Basis of Presentation In 2011, Venoco’s board of directors received a proposal from its then-‑chairman and chief executive officer, Timothy Marquez, to acquire all of the outstanding shares of common stock of Venoco of which he was not the beneficial owner for $12.50 per share in cash. On October 3, 2012, Mr. Marquez and certain of his affiliates, including DPC, completed the going private transaction and acquired all of the outstanding stock of Venoco. As a result, Venoco’s common stock is no longer publicly traded and Venoco is a wholly owned subsidiary of DPC. DPC is majority-‑owned and controlled by Mr. Marquez and his affiliates.

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 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 the financial statements. The Annual Report on Form 10-‑K for the year ended December 31, 2014 for Venoco and DPC 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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Liquidity The additional indebtedness that the Company incurred in connection with and following the going private transaction has increased debt- and liquidity-related risks. We have undertaken a variety of measures to reduce our indebtedness, including ~~sales of our Sacramento Basin and West Montalvo properties for~~ an ~~aggregate price of approximately $450 million. However, our deleveraging efforts have been impacted by various operational issues, including an~~ extended shutdown of the pipeline that transports our South Ellwood field production in 2014 and an additional extended shutdown of the same pipeline resulting from a spill that occurred in the second quarter of 2015. Our deleveraging efforts have also been affected by the dramatic decline in the price of oil that occurred over the second half of 2014 ~~with~~and ~~prices~~continuing ~~remaining~~ low prices in ~~the first half of~~ 2015. As a result of the debt restructuring transaction in April 2015 (see note 2), Venoco’s revolving credit facility was terminated. However, prior to that termination, the Company was required to obtain numerous amendments to and waivers from the lenders under the facility as a result of these factors. We may be forced to seek further amendments or waivers from current or future lenders, and there is no assurance that we will be able to obtain them in a timely manner or at all. The ~~Due to the Company’s need for increased liquidity we completed the~~ April 2015 debt transactions. ~~The transactions~~ resulted in an increase in our overall indebtedness, but improved our near term liquidity. We are currently exploring additional deleveraging efforts and our planned capital expenditures for 2015 are significantly reduced relative to prior years. However, there can be no assurance that any deleveraging efforts will be successful or that we will be able to maintain adequate liquidity and compliance with our debt and other obligations.

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

As of December 31, 2014, DPC has net operating loss carryovers (“"NOLs”") of $499 million for federal income tax purposes and $459 million for financial reporting purposes, and Venoco has net NOLs as of December 31, 2014 of $418 million for federal income tax purposes and $377 million for financial reporting purposes. The difference between the federal income tax NOLs and the financial reporting NOLs of $40 million ~~relates~~for DPC relates to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable. The net operating loss carryovers may be carried back two years and forward twenty years from the year the net operating loss was generated. The net operating losses may be used to offset taxable income through 2034.

Venoco has incurred losses before income taxes in 2008, 2009, and 2012 as well as tax losses in each of the tax years from 2008 through 2013. DPC has incurred losses before income taxes in 2008, 2009, 2012, 2013 and 2014 as well as ~~tax~~taxable losses in each of the tax years from 2008 through 2014. These losses and expected future taxable losses were a key consideration that led each of Venoco and DPC to provide a full valuation allowance against its net deferred tax assets as of December 31, 2014 and ~~June~~ September 30, 2015, since it cannot conclude that it is more likely than not that its net deferred tax assets will be fully realized on future income tax returns.

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings; consistent and sustained pre-tax earnings; sustained or continued improvements in oil and natural gas commodity prices; meaningful incremental oil production and proved reserves from the Company’s development efforts at its Southern California legacy properties; consistent, meaningful production and proved reserves from the Company’s onshore Monterey shale project; meaningful production and proved reserves from the CO2 project at the Hastings Complex; and taxable events resulting from one or more deleveraging transactions. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods.

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

Oil and Gas Properties The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of oil and gas properties. The capitalized costs of oil and gas properties, net of accumulated depreciation, depletion and amortization (DD&A) and the related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying consolidated statements of operations.

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Atthis ~~June 30,~~"ceiling." ~~2015,~~The ~~capitalized~~ceiling ~~costs~~limitation ~~exceeded~~is equal to the ~~ceiling~~sum ~~and~~of: (i) the ~~Company~~present ~~recorded~~value anof ~~impairment~~estimated future net revenues from the projected production of proved oil and gas ~~properties~~reserves, ofexcluding ~~$146~~future ~~million. The~~cash ~~impairment~~outflows atassociated ~~June 30~~with settling asset retirement obligations accrued on the balance sheet, ~~2015~~calculated ~~was~~using ~~primarily~~the ~~due~~average tooil ~~continued~~and ~~low~~natural ~~commodity~~gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices, ~~which~~are ~~resulted~~held inconstant throughout the life of the properties) and a ~~reduction~~discount factor of 10%; (ii) the ~~discounted~~cost ~~present~~of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the ~~Company’s~~costs ~~proved~~being ~~oil~~amortized; and ~~natural~~(iv) ~~gas~~related ~~reserves~~income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying consolidated statements of operations.

~~Reclassifications Certain~~ At ~~amounts~~September in30, ~~prior~~2015, ~~year’s~~capitalized ~~footnotes~~costs toexceeded the ~~financials~~ceiling ~~statements~~and ~~have~~the ~~been~~Company ~~reclassified~~recorded toan impairment of oil and gas properties of $192 million for the quarter ended September 30, 2015. ~~presentation~~During the nine months ended September 30, 2015, the company recorded impairment of $338 million. The ~~Reclassified~~impairment ~~amounts~~was ~~were~~primarily ~~not~~due ~~material~~to continued low commodity prices, which resulted in a reduction of the discounted present value of the Company's proved oil and natural gas reserves. We will likely be required to recognize additional impairments of oil and gas properties in future periods if we continue to experience an extended period of low commodity prices, which will result in a downward adjustment to our estimated proved reserves and the ~~financials~~associated ~~presentation~~present value of estimated future net revenues, or if we incur actual development costs in excess of the estimated costs used in preparing our reserve reports.

Reclassifications Certain amounts in prior years footnotes to the financials statements have been reclassified to the 2015 presentation. Reclassified amounts were not material to the financial presentation.

Recently Issued Accounting Standards In May 2014, the FASB issued new authoritative accounting guidance related to the recognition of revenue. This authoritative accounting guidance is effective for the annual period beginning after December 15, 2017, including interim periods within that reporting period, and is to be applied using one of two acceptable methods. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s consolidated financial statements and disclosures.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements—Going Concern, which requires management to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and provide related footnote disclosures. The guidance is effective for annual and interim reporting periods beginning on or after December 15, 2016. Early adoption is permitted for financial statements that have not been previously issued. The standard allows for either a full retrospective or modified retrospective transition method. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s consolidated financials.

In April 2015, the FASB issued ASU 2015-03 to revise the presentation of debt issuance costs. Under ASU 2015-03, entities will present debt issuance costs in their balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the deferred costs will continue to be included in interest expense. The guidance is effective for annual and interim reporting periods beginning on or after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The standard will be applied retrospectively to all prior periods. The ~~company~~Company is currently evaluating provisions of this guidance and assessing its impact on the Company’s consolidated financials.

2 In August 2015, the FASB issued Accounting Standards Update 2015-15, “Interest — Imputation of Interest: Presentation and Subsequent Measurement of Debt Issuance Associated with Line-of-Credit Arrangements” (“ASU 2015-15”). ASU ~~DEBT~~2015-15 addresses debt issuance costs associated with line-of-credit arrangements by allowing an entity to defer and present such debt issuance costs as an asset regardless of whether there are any outstanding borrowings under the line-of-credit arrangement. ASU 2015-15 is applied retrospectively and is effective for the Company beginning on January 1, 2016. The Company does not believe the adoption of ASU 2015-15 will have a material impact on its financial position, results of operations or cash flows.

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

	Venoco, Inc.				Denver Parent Corporation
	December 31, 2014		June 30, 2015		December 31, 2014		June 30, 2015
Venoco Revolving credit agreement due March 2016	$	65,000	$	—	$	65,000	$	—
Venoco 8.875% senior notes due February 2019	500,000		308,222		500,000		308,222
First lien secured 12% notes due February 2019	—		175,000		—		175,000
Second lien secured 8.875% / 12% notes due February 2019(1)	—		127,874		—		127,874
Term loan facility due December 2017(2)	—		74,250		—		74,250
DPC 12.25% / 13.00% senior PIK toggle notes due August 2018(3)	—		—		275,065		294,001
Total long-term debt	565,000		685,346		840,065		979,347
Less: current portion of long-term debt	—		—		—		—
Long-term debt, net of current portion	$	565,000	$	685,346	$	840,065	$	979,347

(1) Amounts are net of $26.9 million unamortized discount at June 30, 2015.

(2) Amounts are net of $0.8 million unamortized discount at June 30, 2015.

(3) Amounts are net of $4.8 million, and $5.4 million unamortized discount at June 30, 2015 and December 31, 2014, respectively.

The Company recently completed a series of financing transactions in response to its indebtedness and liquidity situation. On April 2, 2015, Venoco entered into agreements relating to three new debt instruments: (i) first lien senior secured notes with an aggregate principal amount of $175 million (the “first lien secured notes”), (ii) second lien senior secured notes with an aggregate principal amount of $150 million (the “second lien secured notes”) and (iii) a $75 million cash collateralized senior secured credit facility (the “term loan facility”). Approximately $72 million of proceeds from the issuance of the first lien secured notes and the term loan facility were used to repay all amounts outstanding under Venoco’s revolving credit facility, which was then terminated. The second lien secured notes were issued in exchange for $194 million aggregate principal amount of, and accrued interest on, Venoco’s outstanding 8.875% senior notes due 2019. The term loan facility was refinanced on June 11, 2015 with a new $75 million secured term loan facility (the “new term loan facility”). The terms of the new debt instruments are summarized in “—Liquidity and Capital Resources—Capital Resources and Requirements.” These transactions increased the Company’s indebtedness overall, but reduced its near-term cash interest expense and provided it with flexibility and additional liquidity that it intends to use to advance longer term projects.

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~~The following summarizes the terms of the agreements governing the Company’s debt outstanding as of June 30, 2015~~2. DEBT

~~First~~ As lien secured notes. The first lien secured notes bear interest at 12% per annum and mature in February 2019. The indenture governing the first lien secured notes includes covenants customary for instruments of ~~this type, including restrictions on Venoco’s ability to incur additional indebtedness, create liens on its properties, pay dividends and make investments and in each case~~ the ~~covenants~~dates ~~are subject to exceptions. The covenants regarding the incurrence of additional indebtedness contain exceptions for~~indicated, ~~among other things, (i) up to $25 million of additional secured or unsecured indebtedness that may be issued or incurred in connection with certain projects approved by~~ the ~~holders of the notes, (ii) up to $50 million of additional second lien secured notes that may be issued in exchange for Venoco~~Company’s ~~outstanding~~long‑term ~~8.875%~~debt ~~senior~~consisted ~~notes due 2019 and (iii) up to $150 million~~ of ~~additional third lien or unsecured indebtedness that may be issued or incurred in exchange for~~ the ~~Venoco’s~~following outstanding 8.875% senior notes or to fund acquisitions. The indenture also includes restrictions on capital expenditures and an operational covenant pursuant to which Venoco is generally required to maintain a specified level of production for each quarterly period until maturity. Other covenants are generally similar to those contained (in the indenture governing the existing 8.875% senior notes. Venoco’s obligations under the first lien secured notes are guaranteed by all of its subsidiaries other than Ellwood Pipeline, Inc. and secured by a first priority lien on substantially all of the assets of Venoco and the guarantors other than the cash collateral under the term loan facility. Venoco may redeem the first lien secured notes at a redemption price of 109% of the principal amount beginning on January 1, 2016 and declining to 100% by January 1, 2019.thousands):

Second lien secured notes. The second lien secured notes bear interest at 8.875% if paid in cash or 12% if paid in kind. Interest may be paid in cash or in kind, at Venoco’s option, for semiannual interest periods commencing within 24 months following issuance. After the initial 24 month period, interest is payable in cash, but may become payable entirely in cash earlier upon the occurrence of certain events. Venoco elected to PIK the first interest payment which was due July 1, 2015. The second lien secured notes mature in February 2019. The indenture governing the second lien secured notes includes covenants, and exceptions thereto, substantially similar to those set forth in the indenture governing the first lien secured notes. Venoco’s obligations under the notes are guaranteed by Venoco’s subsidiaries that guarantee the first lien secured notes and are secured by a second priority lien on the same assets securing its obligations under the first lien secured notes. Venoco may redeem the second lien secured notes on the same terms as the existing 8.875% senior notes.


	Venoco, Inc.				Denver Parent Corporation
	December 31,		September 30,		December 31,		September 30,
	2014		2015		2014		2015
Venoco revolving credit agreement due March 2016	$	65,000	$	—	$	65,000	$	—
Venoco 8.875% senior notes due February 2019		500,000		308,222		500,000		308,222
First lien secured 12% notes due February 2019		—		175,000		—		175,000
Second lien secured 8.875% / 12% PIK notes due February 2019(1)		—		133,843		—		133,843
Term loan facility due December 2017(2)		—		74,324		—		74,324
DPC 12.25% / 13.00% senior PIK toggle notes due August 2018(3)		—		—		275,065		304,176
Total long-term debt		565,000		691,389		840,065		995,565

~~New~~(1) ~~Term loan facility. The term loan facility, which was fully drawn at closing, matures in December 2017.~~ Amounts borrowed under the facility will bear interest at LIBOR plus 4.0% per annum. The facility contains representations, warranties and covenants typical for instruments of this type. Venoco’s obligations under the term loan facility are ~~secured~~net ~~by a first priority lien on cash collateral, which collateral may be released upon the occurrence~~ of ~~certain events, and are guaranteed by Venoco’s subsidiaries that guarantee the first lien secured notes and second lien secured notes~~$25.6 ~~The~~million ~~cash~~unamortized ~~collateral~~discount isat ~~accounted~~September ~~for as restricted cash in the condensed consolidated balance sheets (unaudited). The term facility was incurred under a term loan and security agreement dated as of June 11~~30, 2015 ~~among Venoco, the guarantors and the lenders party thereto.~~

~~Venoco~~(2) ~~8.875%~~Amounts ~~Senior~~are ~~Notes. In~~net ~~February 2011,~~of ~~Venoco issued~~ $~~500 million in 8~~0.~~875%~~7 ~~senior~~million ~~notes~~unamortized ~~due~~discount ~~in February 2019~~ at ~~par.~~September ~~The notes pay interest semi-annually in arrears on February 15 and August 15 of each year. Beginning February 15~~30, 2015~~, Venoco may redeem the notes at a redemption price of 104~~.438% of the principal amount and declining to 100% by February 15, 2017. The notes are senior unsecured obligations and contain operational covenants that, among other things, limit Venoco’s ability to make investments, incur additional indebtedness, issue preferred stock, pay dividends, repurchase its stock, create liens or sell assets.

As(3) ~~part~~Amounts ofare ~~the~~net ~~April 2,~~of ~~2015 debt restructuring,~~ $~~192~~4.6 million ofand ~~the 8~~$5.~~875%~~4 ~~senior notes were redeemed, plus $2~~ million ofunamortized ~~accrued~~discount ~~interest~~at ~~was~~September ~~extinguished. As of June~~ 30, 2015, ~~$308~~and ~~million~~December of31, ~~8.875%~~2014, ~~senior notes are still outstanding~~respectively.

~~DPC~~ The ~~12.25%~~Company /recently ~~13.00%~~completed ~~Senior~~a ~~PIK~~series ~~Toggle Notes. In August 2013, DPC issued $255 million principal amount~~ of ~~12.25%~~financing /transactions ~~13.00%~~in ~~senior~~response ~~PIK~~to ~~toggle~~its ~~notes~~indebtedness ~~due August 2018 at 97.304% of par. Interest on the notes is payable on February 15~~ and ~~August 15~~liquidity ~~of each year~~situation. On ~~The~~April ~~initial~~2, ~~interest~~2015, ~~payment~~Venoco onentered ~~the~~into ~~notes~~agreements ~~was required~~ relating to bethree ~~paid~~new indebt ~~cash.~~instruments: ~~For~~(i) ~~each~~first ~~interest~~lien ~~period~~senior secured notes with ~~after~~an ~~the~~aggregate principal amount of ~~initial~~$175 ~~interest~~million ~~period~~ (~~other than for~~ the ~~final~~" ~~interest~~first ~~period~~lien ~~ending~~secured notes ~~at the stated maturity~~"), ~~which will be paid in cash~~(ii), ~~DPC~~second lien ~~will,~~senior secured notes with inan ~~certain~~aggregate principal amount of ~~circumstances,~~$150 bemillion ~~permitted~~(the to" ~~pay~~second ~~interest~~lien ~~on the~~ secured notes by") ~~increasing~~and ~~the~~(iii) ~~principal~~a ~~amount~~$75 ofmillion ~~the~~cash ~~notes~~collateralized orsenior ~~issuing~~secured ~~new~~credit ~~notes~~facility (~~collectively,~~the “~~PIK~~term ~~interest~~loan facility”). The ~~Cash~~term ~~interest~~loan onfacility ~~the~~was ~~notes~~refinanced ~~accrues~~on atJune ~~the~~11, ~~rate of 12~~2015.~~25%~~ ~~per~~Approximately ~~annum.~~$72 ~~PIK~~million ~~interest~~of onproceeds from the ~~notes~~issuance ~~accrues~~of at the ~~rate~~first oflien ~~13.00%~~secured ~~per~~notes ~~annum~~and ~~until~~ the ~~next~~term ~~payment~~loan offacility ~~cash~~were ~~interest.~~used ~~The~~to ~~August 2014~~repay ~~interest~~all ~~payment~~amounts ~~was~~outstanding ~~paid~~under ~~25%~~Venoco’s inrevolving ~~cash~~credit ~~and~~facility, ~~75%~~which ~~PIK~~was ~~interest~~then terminated. The ~~February~~second lien ~~and~~secured notes were ~~August 2015~~issued ~~interest~~in ~~payments~~exchange for ~~were~~$194 ~~paid~~million ~~entirely~~aggregate principal amount of, asand ~~PIK~~ accrued interest. on, ~~DPC~~Venoco’s isoutstanding a8.875% ~~holding~~senior notes due ~~company~~2019. The ~~that~~term ~~owns~~loan nofacility ~~material~~was ~~assets~~refinanced ~~other~~on ~~than~~June ~~stock of Venoco; accordingly~~11, it2015 ~~will~~with bea ~~able~~new to$75 ~~pay~~million ~~cash~~secured ~~interest~~term onloan ~~its~~facility ~~notes only to~~ (the ~~extent~~“new ~~that~~term itloan ~~receives cash dividends or distributions from Venoco~~facility”). The ~~notes~~terms ~~are~~of ~~not~~the ~~currently~~new ~~guaranteed~~debt byinstruments ~~any~~are ofsummarized ~~DPC’s subsidiaries~~below. ~~DPC~~These ~~may~~transactions ~~redeem~~increased ~~all or any part of~~ the ~~notes~~Company’s onindebtedness ~~and after August 15~~overall, ~~2015~~but atreduced aits ~~redemption~~near-term ~~price~~cash ofinterest ~~106.125%~~expense ~~of the principal amount~~ and ~~declining~~provided toit ~~100%~~with byflexibility ~~August 15, 2017. The notes are senior unsecured obligations~~ and ~~contain~~additional ~~operational~~liquidity ~~covenants~~ that, ~~among~~it ~~other~~intends ~~things,~~to ~~limit~~use ~~the Company’s ability~~ to ~~make~~advance ~~investments,~~longer ~~incur~~term ~~additional indebtedness, issue preferred stock, pay dividends, repurchase stock, create liens or sell assets~~projects.

The following summarizes the terms of the agreements governing the Company’s debt outstanding as of September 30, 2015.

First lien secured notes. The first lien secured notes bear interest at 12% per annum and mature in February 2019. The indenture governing the first lien secured notes includes covenants customary for instruments of this type, including restrictions on Venoco's ability to incur additional indebtedness, create liens on its properties, pay dividends and make investments, in each case subject to exceptions. The covenants regarding the incurrence of additional indebtedness contain exceptions for, among other things, (i) up to $25 million of additional secured or unsecured indebtedness that may be issued or incurred in connection with certain projects approved by the holders of the notes, (ii) up to $50 million of additional second lien secured notes that may be issued in exchange for Venoco's outstanding 8.875% senior notes due 2019 and (iii) up to $150 million of additional third lien or unsecured indebtedness that may be issued or incurred in exchange for the Venoco's outstanding 8.875% senior notes or to fund acquisitions. The indenture also includes restrictions on capital expenditures and an operational covenant pursuant to which Venoco is generally required to maintain a specified level of production for each quarterly period until maturity. Other covenants are generally similar to those contained in the indenture governing the existing 8.875% senior notes. Venoco's obligations under the first lien secured notes are guaranteed by all of its subsidiaries other than Ellwood Pipeline, Inc. and secured

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~~The~~by ~~Company accounted for the April 2015 debt exchange as~~ a ~~debt~~first ~~extinguishment~~priority ~~because~~lien ~~the~~on ~~present~~substantially ~~value~~all of the ~~cash~~assets ~~flows~~of ~~second~~Venoco ~~lien~~and ~~notes were at least 10% different from~~ the ~~present~~guarantors ~~value~~other ofthan the ~~remaining~~ cash ~~flows~~collateral under the ~~terms~~term ofloan ~~the original 8~~facility.~~875%~~ Venoco ~~notes. The~~may ~~Company~~redeem ~~recognized a gain of $68 million on~~ the ~~exchange,~~first ~~which~~lien issecured ~~net~~notes ofat ~~the~~a ~~write~~redemption ~~off~~price of ~~$4.5 million associated with debt issuances costs related to the Revolver and the Venoco 8.875~~109% ~~notes. The gain is composed~~ of ~~$43.7 million related to~~ the ~~extinguishment~~principal ~~plus~~amount anbeginning ~~additional $28 million due to the difference between the carrying value and the fair value of the second lien notes~~ on ~~the~~January ~~date~~1, of2016 ~~the exchange. The $28 million was accounted for as a discount on the second lien note~~ and ~~will~~declining beto ~~amortized~~100% ~~over~~by ~~the~~January ~~life~~1, ~~of the debt through interest expense~~2019. ~~The gain is recorded in ‘Loss (gain) on extinguishment of debt’ in the condensed consolidate statements of operations (unaudited).~~

Second lien secured notes. The ~~Company~~second ~~was~~lien secured notes bear interest at 8.875% if paid in ~~compliance~~cash ~~with~~or ~~all~~12% ~~debt~~if ~~covenants~~paid in kind. Interest may be paid in cash or in kind, at ~~June 30~~Venoco's option, ~~2015~~for semiannual interest periods commencing within 24 months following issuance. After the initial 24 month period, interest is payable in cash, but may become payable entirely in cash earlier upon the occurrence of certain events. The second lien secured notes mature in February 2019. The indenture governing the second lien secured notes includes covenants, and exceptions thereto, substantially similar to those set forth in the indenture governing the first lien secured notes. Venoco's obligations under the notes are guaranteed by Venoco's subsidiaries that guarantee the first lien secured notes and are secured by a second priority lien on the same assets securing its obligations under the first lien secured notes. Venoco may redeem the second lien secured notes on the same terms as the existing 8.875% senior notes.

Term loan facility. The term loan facility, which was fully drawn at closing, matures in December 2017. Amounts borrowed under the facility will bear interest at LIBOR plus 4.0% per annum. The facility contains representations, warranties and covenants typical for instruments of this type. Venoco's obligations under the term loan facility are secured by a first priority lien on cash collateral, which collateral may be released upon the occurrence of certain events, and are guaranteed by Venoco's subsidiaries that guarantee the first lien secured notes and second lien secured notes. The term facility was incurred under a term loan and security agreement dated as of June 11, 2015 among Venoco, the guarantors and the lenders party thereto.

Venoco 8.875% Senior Notes. In February 2011, Venoco issued $500 million in 8.875% senior notes due in February 2019 at par. The notes pay interest semi‑annually in arrears on February 15 and August 15 of each year. Beginning February 15, 2015, Venoco may redeem the notes at a redemption price of 104.438% of the principal amount and declining to 100% by February 15, 2017. The notes are senior unsecured obligations and contain operational covenants that, among other things, limit Venoco’s ability to make investments, incur additional indebtedness, issue preferred stock, pay dividends, repurchase its stock, create liens or sell assets.

As part of the April 2, 2015 debt restructuring, $192 million of the 8.875% senior notes were redeemed and $2 million of accrued interest was extinguished. As of September 30, 2015, $308 million 8.875% senior notes are still outstanding.

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 August 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 was required to be paid in cash. 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 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 accrues at the rate of 12.25% per annum. PIK interest on the notes accrues at the rate of 13.00% per annum until the next payment of cash interest. The August 2014 interest payment was paid 25% in cash and 75% PIK interest, and the February and August 2015 interest payments were paid entirely as PIK interest. 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 extent that it receives cash dividends or distributions from Venoco. The notes are not currently guaranteed by any of DPC’s subsidiaries. DPC may also redeem all or any part of the notes on and after August 15, 2015 at a redemption price of 106.125% of the principal amount and declining to 100% by August 15, 2017. The notes are senior unsecured obligations and contain operational covenants that, among other things, limit the Company’s ability to make investments, incur additional indebtedness, issue preferred stock, pay dividends, repurchase stock, create liens or sell assets.

The Company accounted for the April 2015 second lien secured note debt exchange as a debt extinguishment. The Company recognized a gain of $68 million on the exchange, which is net of the write off of $4.5 million associated with debt issuances costs related to the Venoco’s revolving credit facility and 8.875% notes. The gain is composed of $44 million related to the extinguishment plus an additional $28 million due to the difference between the carrying value

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and the fair value of the second lien notes on the date of the exchange. The $28 million was accounted for as a discount on the second lien note and will be amortized over the life of the debt through interest expense. The gain is recorded in ‘Loss (gain) on extinguishment of debt’ in the condensed consolidated statements of operations (unaudited).

The Company was in compliance with all debt covenants at September 30, 2015.

3. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Derivative Agreements. The Company utilizes swap and collar agreements ~~and option contracts~~ in an effort to hedge the effect of commodity price changes on its cash flows. 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 cash flows 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 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.

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						Nine Months Ended
		2014			2015			2014			2015
	September 30,						September 30,
Realized commodity derivative losses (gains)		$	4,530		$	(26,312	)	$	8,055		$	(40,262	)
	2014			2015			2014			2015
Unrealized commodity derivative losses (gains) for changes in fair value		14,380			36,017			8,760			37,062
Realized commodity derivative losses (gains)	$	1,355		$	(16,840)		$	9,410		$	(58,932)
Commodity derivative losses (gains), net		$	18,910		$	9,705		$	16,815		$	(3,200	)
Unrealized commodity derivative losses (gains) for changes in fair value		(31,691)			(4,599)			(22,931)			34,293
Commodity derivative losses (gains), net	$	(30,336)		$	(21,439)		$	(13,521)		$	(24,639)

As of ~~June~~ September 30, 2015, the Company had entered into certain swap and collar agreements related to its oil production. The aggregate economic effects of those agreements are summarized below. Location and quality differentials attributable to the Company’s properties are not included in the following prices. The agreements provide for monthly settlement based on the differential between the agreement price and the price per the applicable index, Inter-Continental Exchange Brent (“Brent”).

	Oil (Brent)
	Barrels/day	Weighted Avg. Prices per Bbl
		Weighted Avg.
January 1 - December 31, 2015:
	Barrels/day	Prices per Bbl
Swaps	460	$	100.40
January 1 - December 31, 2015:
Collars	4,135	$	90.00/$100.00
Swaps	460	$	100.40
January 1 - December 31, 2016:
Collars	4,135	$	90.00	/	$	100.00
Swap	1,715	$	96.00
January 1 - December 31, 2016:
Swaps	1,715	$	96.00

In connection with the debt transaction that ~~occured~~occurred in April 2015 ~~the~~Venoco ~~Company~~ unwound its 2016 derivative contract with ABN AMRO which hedged 1,715 bbls of ~~its~~our ~~2016~~2014 oil production. As a result we received $15.6 million in proceeds which contributed to the nine months ended September 30, 2015 realized gain of $4058.3 9 million.

Fair Value of Derivative Instruments. The estimated fair values of derivatives included in the condensed consolidated balance sheets at June 30, 2015 and December 31, 2014 are summarized below. The net fair value of the Company’s derivatives decreased by $38.9 million from a net asset of $78.1 million at December 31, 2014 to a net asset of $39.2 million at June 30, 2015, 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 2015. 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 13

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Fair Value of Derivative Instruments. The estimated fair values of derivatives included in the condensed consolidated balance sheets at September 30, 2015 and December 31, 2014 are summarized below. The net fair value of the Company’s derivatives decreased by $34.3 million from a net asset of $78.1 million at December 31, 2014 to a net asset of $43.8 million at September 30, 2015, 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 2015. 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 (in thousands).

	December 31, 2014		June 30, 2015
	December 31,		September 30,
	2014		2015
Current Assets—Commodity derivatives:
Oil derivative contracts	$	48,298	$	3037,~~545~~240
Noncurrent Assets—Commodity derivatives:
Oil derivative contracts	~~29,793~~	29,793	~~8,653~~	6,558
Net derivative asset (liability)	$	78,091	$	39,198
Net derivative asset	$	78,091	$	43,798

4. ASSET RETIREMENT OBLIGATIONS

The following table summarizes the activities for the Company’s asset retirement obligations for the ~~six~~nine months ended ~~June~~ September 30, 2014 and 2015 (in thousands):

	Six Months Ended June 30,
	Nine Months Ended
	September 30,
	2014			2015
Asset retirement obligations at beginning of period	$	38,182		$	30,851
Revisions of estimated liabilities	~~(594~~	(594)	)	~~1,788~~	1,789
Liabilities incurred or acquired	~~221~~	221		—	—
Liabilities settled	(599		)	—
Liabilities settled or disposed		(599)			—
Accretion expense	~~1,223~~	1,852		~~1,011~~	1,536
Asset retirement obligations at end of period	~~38,433~~	39,062		~~33,650~~	34,176
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)	~~(700~~	(500)	)	~~(500~~	(1,100)	)
Long-term asset retirement obligations	$	3738,~~733~~562		$	33,~~150~~076

The difference between the ending balance as of September 30, 2014 and the beginning balance 2015 is a result of the sale of the West Montalvo field.

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

5. SHARE-‑BASED PAYMENTS

The Company has granted cash settlement or liability awards to officers, directors and certain employees of the Company including rights-‑to-‑receive awards (RTR), restricted share unit awards (RSUs), share appreciation rights (SARs) and ESOP restricted share units. 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 in 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.

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6. 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.

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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~~ September 30, 2015 (in thousands).

	Level 1		Level 2		Level 3		Fair Value
									Fair Value
Assets (Liabilities):
									as of
Commodity derivative contracts	—		39,198		—		39,198
									September 30,
Share-based compensation	—		—		(295	)	(295	)
	Level 1			Level 2			Level 3		2015
Assets (Liabilities):
Commodity derivative contracts	$	—		$	43,798		$	—	$	43,798
Share-based compensation		—			—			(556)		(556)

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

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.

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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 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), which represent primarily share-based compensation liabilities, designated as Level 3 in the valuation hierarchy (in thousands):

	Six Months Ended June 30,
	Nine Months Ended
	September 30,
	2014			2015
Fair value liability, beginning of period	$	(20,928)	)	$	(1,038)	)
Transfers into Level 3(1)	~~(4,235~~	(5,507)	)	~~(251~~	(589)	)
Transfers out of Level 3(2)	~~5,162~~	5,555		~~489~~	566
Change in fair value of Level 3	~~445~~	9,322		~~505~~	505
Fair value liability, end of period	$	(1911,~~556~~558)	)	$	(~~295~~556)	)

14(1) The transfers into Level 3 liability during the first nine months of 2015 and 2014 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 2015 and 2014 relate to cash settlements of RSU grants, and forfeitures of RSU and SAR 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 and the term loan facility approximated fair value because the interest rates of these facilities were variable. The fair value of the Venoco senior notes and the DPC senior PIK toggle notes listed in the table below was derived from available market data (Level 1). We used available market

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~~(1) The~~data ~~transfers~~and ~~into~~valuation techniques (Level 3 ~~liability~~2) ~~during~~to estimate the ~~first~~fair ~~half~~value of ~~2015~~the ~~and~~first ~~2014~~lien ~~relate~~and tosecond ~~RSU,~~lien ~~SAR~~notes. ~~and~~This ~~ESOP~~disclosure ~~grants~~does ~~made~~not byimpact ~~the~~our ~~Company~~financial ~~to officers~~position, ~~directors~~results ~~and~~of ~~certain~~operations ~~employees,~~or ~~and~~cash ~~requisite~~flows ~~service~~(in ~~period expense~~thousands).

(2) The transfers out of Level 3 liability during the first half of 2015 and 2014 relate to cash settlements of RSU grants, and forfeitures of RSU, SAR and ESOP grants as a result of employee terminations.


	December 31, 2014				September 30, 2015
	Carrying		Estimated		Carrying		Estimated
	Value		Fair Value		Value		Fair Value
Venoco:
Revolving credit agreement	$	65,000	$	65,000	$	—	$	—
Venoco 8.875% senior notes due February 2019		500,000		262,000		308,222		57,021
First lien secured 12% notes due February 2019		—		—		175,000		141,210
Second lien secured 8.875% / 12% PIK notes due February 2019		—		—		133,843		87,072
Term loan facility due December 2017		—		—		74,324		74,324
Denver Parent Corporation:
12.25% / 13.00% senior PIK toggle notes		275,065		120,369		304,176		14,633

~~Fair~~ Assets ~~Value of Financial Instruments. The Company’s financial instruments consist primarily of cash~~ and ~~cash~~Liabilities ~~equivalents,~~Measured ~~accounts~~on ~~receivable~~a ~~and~~Non‑recurring ~~payable, derivatives (discussed above) and long-term debt~~Basis. The ~~carrying~~Company ~~values~~uses ~~of cash equivalents and accounts receivable and payable are representative of their~~ fair ~~values~~value ~~due~~ to ~~their~~determine ~~short-term~~the ~~maturities.~~value ~~The carrying amount~~ of ~~Venoco’s~~its ~~revolving~~asset ~~credit~~retirement ~~facility~~obligations (~~which was paid off in April 2015~~“ARO”) ~~and~~at the ~~term~~point ~~loan facility approximated fair value because the interest rate~~ of ~~the facilities is variable~~inception. The ~~fair~~inputs ~~value~~used ofto ~~the~~determine ~~Venoco~~such ~~senior~~fair ~~notes~~value ~~and~~under the ~~DPC~~expected ~~PIK~~present ~~toggle~~value ~~notes~~technique ~~listed~~are inprimarily ~~the~~based ~~table~~upon ~~below~~internal ~~was~~estimates ~~derived~~prepared ~~from~~by ~~available~~reservoir ~~market~~engineers ~~data~~for ~~(Level 1).~~costs Weof ~~used~~dismantlement, ~~available~~removal, ~~market~~site ~~data~~reclamation and ~~valuation~~similar ~~techniques~~activities ~~(Level 2)~~associated towith ~~estimate~~ the ~~fair~~Company’s ~~value~~oil ofand ~~the~~gas ~~Venoco~~properties ~~first lien~~ and ~~second~~would ~~lien~~be ~~notes.~~classified ~~This~~as ~~disclosure~~Level 3 ~~does not impact our financial position, results of operations or cash flows (in thousands)~~inputs.

	December 31, 2014				June 30, 2015
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Venoco:
Revolving credit agreement	$	65,000	$	65,000	$	—	$	—
8.875% senior notes	500,000		262,000		308,222		95,583
First lien secured note	—		—		175,000		153,132
Second lien secured note	—		—		127,875		98,871
Term loan facility	—		—		74,250		74,250
Denver Parent Corporation:
12.25% / 13.00% senior PIK toggle notes	275,065		120,369		294,001		27,195

Assets and Liabilities Measured on a Non-recurring Basis. The Company uses fair value to determine the value of its asset retirement obligations (“ARO”). The inputs used to determine such fair value under the expected present value technique are primarily based upon internal estimates prepared by reservoir engineers for costs of dismantlement, removal, site reclamation and similar activities associated with the Company’s oil and gas properties and would be classified as Level 3 inputs.

7. 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.

Delaware Litigation— In August 2011 Timothy Marquez, the then-Chairman and CEO of Venoco, submitted a nonbinding proposal to the board of directors of Venoco to acquire all of the shares of Venoco he did not beneficially own for $12.50 per share in cash (the “Marquez Proposal”). As a result of that proposal, five lawsuits were filed in the Delaware Court of Chancery in 2011 against Venoco and each of its directors by shareholders alleging that Venoco and its directors had breached their fiduciary duties to the shareholders in connection with the Marquez Proposal. On January 16, 2012, Venoco entered into a Merger Agreement with Mr. Marquez and certain of his affiliates pursuant to which Venoco, Mr. Marquez and his affiliates would effect the going private transaction. Following announcement of the Merger Agreement, five additional suits were filed in Delaware and three suits were filed in federal court in Colorado naming as defendants Venoco 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 resulting from of the breach of fiduciary duties by the defendants. The Colorado actions have been administratively closed pending resolution of the Delaware case. Venoco has reviewed the allegations contained in the amended complaint and believes they are without merit. Trial is expected to occur in 2016.

Denbury Arbitration— In January 2013 Venoco and its wholly owned subsidiary, TexCal Energy South Texas, L.P. (“TexCal”), notified Denbury Resources, Inc. through its subsidiary Denbury Onshore, LLC (“Denbury”) that it was invoking the arbitration provisions contained in contracts between TexCal and Denbury pursuant to which TexCal conveyed its interest in the Hastings Complex to Denbury and retained a reversionary interest. Denbury is obligated to convey the reversionary interest to TexCal at “payout” as defined in the contracts. The dispute involves the calculation of the cost of CO2 delivered to the Hastings Complex which is used in Denbury’s enhanced oil recovery operations. The Company believes that Denbury has materially overcharged the payout account for the cost of CO2 and the cost of transporting it to the Hastings Complex. In December 2013, the three judge arbitration panel unanimously agreed with Venoco’s position. In January 2014 Denbury requested that the arbitration panel modify its decision in a way

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the cost of transporting it to the Hastings Complex. In December 2013, the three judge arbitration panel unanimously agreed with Venoco’s position. In January 2014 Denbury requested that the arbitration panel modify its decision in a way that could increase the cost of CO2. In March 2014 the Arbitration Panel modified its original award consistent with the Company’s position and awarded the Company approximately $1.8 million in attorneys’ fees and costs incurred in the arbitration. In late March 2014 Denbury appealed the arbitration ruling to the District Court for Harris County, Texas asking the court to vacate the arbitration award. On February 11, 2015 the District Court granted Venoco’s motion to confirm the arbitration award. In March 2015, Denbury filed a motion for a new trial with the District Court which was denied. Denbury appealed the case to the Texas Court of Appeals in May 2015.

Other— In addition, Venoco is a party from time to time to other claims and legal actions that arise in the ordinary course of business. Venoco 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.

8. ~~RELATED~~Related ~~PARTY~~Party ~~TRANSACTIONS~~Transactions

The Company has entered into a non-exclusive aircraft sublease agreement with TimBer, LLC, a company owned by Mr. Marquez and his wife. The Company incurred costs related to the agreement of $0.35 million and $0.45 million in the first ~~half~~nine months of 2014 and 2015, respectively.

On April 27, 2015, Mr. Marquez entered into an amendment to his existing employment agreement pursuant to which he received $1.5 million in recognition of his leadership in completing the recent debt restructuring transaction.

9. GUARANTOR FINANCIAL INFORMATION

All subsidiaries of Venoco other than Ellwood Pipeline Inc. (“Guarantors”) have fully and unconditionally guaranteed, on a joint and several basis, Venoco’s obligations under its 8.875% senior notes, 12% senior secured notes and 8.875% senior secured 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, 2015. All Guarantors are 100% owned by Venoco. Presented below are Venoco’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.

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CONDENSED CONSOLIDATING BALANCE SHEETS

AT DECEMBER 31, 2014 (Unaudited)

(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
							Non-
				Guarantor			Guarantor
	Venoco, Inc.			Subsidiaries			Subsidiary			Eliminations			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	15,455		$	—		$	—		$	—		$	15,455
Accounts receivable	~~14,140~~	14,140		56	56		~~716~~	716		—	—		~~14,912~~	14,912
Inventories	~~3,370~~	3,370		—	—		—	—		—	—		~~3,370~~	3,370
Other current assets	~~4,715~~	4,715		—	—		—	—		—	—		~~4,715~~	4,715
Commodity derivatives	~~48,298~~	48,298		—	—		—	—		—	—		~~48,298~~	48,298
TOTAL CURRENT ASSETS	~~85,978~~	85,978		56	56		~~716~~	716		—	—		~~86,750~~	86,750
PROPERTY, PLANT & EQUIPMENT, NET	~~654,549~~	654,549		~~(184,362~~	(184,362)	)	~~18,327~~	18,327		—	—		~~488,514~~	488,514
COMMODITY DERIVATIVES	~~29,793~~	29,793		—	—		—	—		—	—		~~29,793~~	29,793
INVESTMENTS IN AFFILIATES	~~563,401~~	563,401		—	—		—	—		~~(563,401~~	(563,401)	)	—	—
OTHER	~~11,138~~	11,138		59	59		—	—		—	—		~~11,197~~	11,197
TOTAL ASSETS	~~1,344,859~~	1,344,859		~~(184,247~~	(184,247)	)	~~19,043~~	19,043		~~(563,401~~	(563,401)	)	~~616,254~~	616,254
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	~~20,535~~	20,535		—	—		—	—		—	—		~~20,535~~	20,535
Interest payable	~~17,329~~	17,329		—	—		—	—		—	—		~~17,329~~	17,329
Commodity derivatives	—			—			—			—			—
Share-based compensation		2,236			—			—			—			2,236
Share-based compensation	2,236			—			—			—			2,236
TOTAL CURRENT LIABILITIES:		40,100			—			—			—			40,100
TOTAL CURRENT LIABILITIES:	40,100			—			—			—			40,100
LONG-TERM DEBT		565,000			—			—			—			565,000
LONG-TERM DEBT	565,000			—			—			—			565,000
COMMODITY DERIVATIVES		—			—			—			—			—
COMMODITY DERIVATIVES	—			—			—			—			—
ASSET RETIREMENT OBLIGATIONS		27,906			1,652			793			—			30,351
ASSET RETIREMENT OBLIGATIONS	27,906			1,652			793			—			30,351
SHARE-BASED COMPENSATION		648			—			—			—			648
SHARE-BASED COMPENSATION	648			—			—			—			648
INTERCOMPANY PAYABLES (RECEIVABLES)		735,845			(655,326)			(80,555)			36			—
INTERCOMPANY PAYABLES (RECEIVABLES)	735,845			(655,326		)	(80,555		)	36			—
TOTAL LIABILITIES		1,369,499			(653,674)			(79,762)			36			636,099
TOTAL LIABILITIES	1,369,499			(653,674		)	(79,762		)	36			636,099
TOTAL STOCKHOLDERS’ EQUITY (DEFICIT)		(24,640)			469,427			98,805			(563,437)			(19,845)
TOTAL STOCKHOLDERS’ EQUITY(DEFICIT)	(24,640		)	469,427			98,805			(563,437		)	(19,845		)
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	$	1,344,859		$	(184,247)		$	19,043		$	(563,401)		$	616,254
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY(DEFICIT)	$	1,344,859		$	(184,247	)	$	19,043		$	(563,401	)	$	616,254

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CONDENSED CONSOLIDATING BALANCE SHEETS

AT ~~JUNE~~SEPTEMBER 30, 2015 (Unaudited)

(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
							Non-
				Guarantor			Guarantor
	Venoco, Inc.			Subsidiaries			Subsidiary			Eliminations			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	~~114~~94,~~009~~708		$	—		$	—		$	—		$	~~114~~94,~~009~~708
Restricted funds	~~79,595~~	79,588		—	—		—	—		—	—		~~79,595~~	79,588
Accounts receivable	~~8,550~~	9,451		56	48		~~433~~	480		—	—		~~9,039~~	9,979
Inventories	~~3,299~~	3,329		—	—		—	—		—	—		~~3,299~~	3,329
Prepaid expenses and other current assets	2,272			—			—			—			2,272
Other current assets		4,088			—			—			—			4,088
Commodity derivatives	~~30,545~~	37,240		—	—		—	—		—	—		~~30,545~~	37,240
TOTAL CURRENT ASSETS	~~238,270~~	228,404		56	48		~~433~~	480		—	—		~~238,759~~	228,932
PROPERTY, PLANT & EQUIPMENT, NET	~~501,391~~	319,457		~~(184,415~~	(184,441)	)	~~17,909~~	17,700		—	—		~~334,885~~	152,716
COMMODITY DERIVATIVES	~~8,653~~	6,558			—			—			—		~~8,653~~	6,558
INVESTMENTS IN AFFILIATES	~~563,401~~	563,401		—	—		—	—		~~(563,401~~	(563,401)	)	—	—
OTHER	~~16,532~~	15,571		60	59		—	—		—	—		~~16,592~~	15,630
TOTAL ASSETS	~~1,328,247~~	1,133,391		~~(184,299~~	(184,334)	)	~~18,342~~	18,180		~~(563,401~~	(563,401)	)	~~598,889~~	403,836
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	~~15,019~~	24,188		—	—		—	—		—	—		~~15,019~~	24,188
Interest payable	~~15,926~~	8,814		—	—		—	—		—	—		~~15,926~~	8,814
Commodity derivatives	—			—			—			—			—
Commodity		—			—			—			—			—
Share-based compensation	~~176~~	191		—	—		—	—		—	—		~~176~~	191
TOTAL CURRENT LIABILITIES:	~~31,121~~	33,193		—	—		—	—		—	—		~~31,121~~	33,193
LONG-TERM DEBT	~~685,346~~	691,389		—	—		—	—		—	—		~~685,346~~	691,389
COMMODITY DERIVATIVES	—			—			—			—			—
COMMODITY		—			—			—			—			—
ASSET RETIREMENT OBLIGATIONS	~~30,679~~	30,566		~~1,669~~	1,703		~~802~~	807		—	—		~~33,150~~	33,076
SHARE-BASED COMPENSATION	~~235~~	463		—	—		—	—		—	—		~~235~~	463
INTERCOMPANY PAYABLES (RECEIVABLES)	~~742,315~~	744,593		~~(655,544~~	(655,691)	)	~~(86,807~~	(88,938)	)	36	36		—	—
TOTAL LIABILITIES	~~1,489,696~~	1,500,204		~~(653,875~~	(653,988)	)	~~(86,005~~	(88,131)	)	36	36		~~749,852~~	758,121
TOTAL STOCKHOLDERS’ EQUITY	(161,449		)	469,576			104,347			(563,437		)	(150,963		)
TOTAL STOCKHOLDERS’ EQUITY (DEFICIT)		(366,813)			469,654			106,311			(563,437)			(354,285)
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,328,247		$	(184,299	)	$	18,342		$	(563,401	)	$	598,889
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	$	1,133,391		$	(184,334)		$	18,180		$	(563,401)		$	403,836

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

THREE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, 2014 (Unaudited)

(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries		Non-Guarantor Subsidiary			Eliminations			Consolidated
				Guarantor		Non-‑Guarantor‑
	Venoco, Inc.			Subsidiaries		Subsidiary			Eliminations			Consolidated
REVENUES:
Oil and natural gas sales	$	6656,~~247~~953		$	~~316~~289	$	—		$	—		$	6657,~~563~~242
Other	~~125~~	119		—	—	~~1,882~~	2,058		~~(1,531~~	(1,568)	)	~~476~~	609
Total revenues	~~66,372~~	57,072		~~316~~	289	~~1,882~~	2,058		~~(1,531~~	(1,568)	)	~~67,039~~	57,851
EXPENSES:
Lease operating expense	~~17,240~~	17,430		12	10	~~933~~	785		—	—		~~18,185~~	18,225
Production and property taxes	~~2,231~~	1,961		15	2	24	161		—	—		~~2,270~~	2,124
Transportation expense	~~1,482~~	1,520		3	4	—	—		~~(1,436~~	(1,473)	)	49	51
Depletion, depreciation and amortization	~~11,561~~	11,524		26	27	~~207~~	208		—	—		~~11,794~~	11,759
Impairment of oil and gas properties	~~817~~	—		—	—	—	—		—	—		~~817~~	—
Accretion of asset retirement obligations	~~515~~	586		31	32	10	11		—	—		~~556~~	629
General and administrative, net of amounts capitalized	~~8,948~~	1,294		1	—	~~136~~	153		~~(95~~	(95)	)	~~8,990~~	1,352
Total expenses	~~42,794~~	34,315		88	75	~~1,310~~	1,318		~~(1,531~~	(1,568)	)	~~42,661~~	34,140
Income (loss) from operations	23,578			228		572			—			24,378
Income from operations		22,757			214		740			—			23,711
FINANCING COSTS AND OTHER:
Interest expense, net	~~14,836~~	15,168		—	—	~~(1,485~~	(1,533)	)	—	—		~~13,351~~	13,635
Amortization of deferred loan costs	~~863~~	887		—	—	—	—		—	—		~~863~~	887
Commodity derivative losses (gains), net	18,910			—		—			—			18,910
Loss on extinguishment of debt		—			—		—			—			—
Total financing costs and other	34,609			—		(1,485		)	—			33,124
Commodity derivative losses (gains), net		(30,336)			—		—			—			(30,336)
Equity in subsidiary income	1,417			—		—			(1,417		)	—
Total financing costs and other		(14,281)			—		(1,533)			—			(15,814)
Income (loss) before income taxes	(9,614		)	228		2,057			(1,417		)	(8,746		)
Equity in subsidiary income		1,543			—		—			(1,543)			—
Income tax provision (benefit)	(868		)	86		782			—			—
Income (loss) before income taxes		38,581			214		2,273			(1,543)			39,525
Net income (loss)	$	(8,746	)	$	142	$	1,275		$	(1,417	)	$	(8,746	)
Income tax provision (benefit)		(944)			82		863			(1)			—
Net income (loss)	$	39,525		$	132	$	1,410		$	(1,542)		$	39,525

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

THREE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, 2015 (Unaudited)

(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries		Non-Guarantor Subsidiary			Eliminations			Consolidated
				Guarantor		Non-‑Guarantor
	Venoco, Inc.			Subsidiaries		Subsidiary			Eliminations			Consolidated
REVENUES:
Oil and natural gas sales	$	1910,~~151~~491		$	~~166~~155	$	—		$	—		$	1910,~~317~~646
Other	~~127~~	127		—	—	~~1,949~~	1,402		~~(1,523~~	(1,021)	)	~~553~~	508
Total revenues	~~19,278~~	10,618		~~166~~	155	~~1,949~~	1,402		~~(1,523~~	(1,021)	)	~~19,870~~	11,154
EXPENSES:
Lease operating expense	~~12,536~~	12,261		16	7	~~654~~	687		—	—		~~13,206~~	12,955
Production and property taxes	~~1,956~~	584		1	1	70	162		—	—		~~2,027~~	747
Transportation expense	~~1,461~~	966		9	9	—	—		~~(1,424~~	(921)	)	46	54
Depletion, depreciation and amortization	~~6,999~~	4,024		26	26	~~209~~	210		—	—		~~7,234~~	4,260
Impairment of oil and gas properties	~~146,030~~	191,800		—	—	—	—		—	—		~~146,030~~	191,800
Accretion of asset retirement obligations	~~474~~	487		35	34	5	4		—	—		~~514~~	525
General and administrative, net of amounts capitalized	~~7,000~~	5,865		—	—	~~136~~	124		~~(99~~	(99)	)	~~7,037~~	5,890
Total expenses	~~176,456~~	215,987		87	77	~~1,074~~	1,187		~~(1,523~~	(1,020)	)	~~176,094~~	216,231
Income (loss) from operations	~~(157,178~~	(205,369)	)	79	78	~~875~~	215		—	(1)		~~(156,224~~	(205,077)	)
FINANCING COSTS AND OTHER:
Interest expense, net	~~21,622~~	20,459		—	—	~~(1,696~~	(1,748)	)	—	—		~~19,926~~	18,711
Amortization of deferred loan costs	~~1,480~~	973		—	—	—	—		—	—		~~1,480~~	973
Loss (gain) on extinguisment of debt	(67,515		)	—		—			—			(67,515		)
Loss on extinguishment of debt		—			—		—			—			—
Commodity derivative losses (gains), net	~~9,705~~	(21,439)		—	—	—	—		—	—		~~9,705~~	(21,439)
Total financing costs and other	~~(34,708~~	(7)	)	—	—	~~(1,696~~	(1,748)	)	—	—		~~(36,404~~	(1,755)	)
Equity in subsidiary income	~~1,644~~	1,266		—	—	—	—		~~(1,644~~	(1,266)	)	—	—
Income (loss) before income taxes	~~(120,826~~	(204,096)	)	79	78	~~2,571~~	1,963		~~(1,644~~	(1,267)	)	~~(119,820~~	(203,322)	)
Income tax provision (benefit)	~~(1,007~~	(776)	)	30	30	~~977~~	746		—	—		—	—
Net income (loss)	$	(~~119~~203,~~819~~320)	)	$	4948	$	1,~~594~~217		$	(1,~~644~~267)	)	$	(~~119~~203,~~820~~322)	)

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

~~SIX~~ NINE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, 2014 (Unaudited)

(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries		Non-Guarantor Subsidiary			Eliminations			Consolidated
				Guarantor		Non-Guarantor
	Venoco, Inc.			Subsidiaries		Subsidiary			Eliminations			Consolidated
REVENUES:
Oil and natural gas sales	$	~~128~~185,~~460~~413		$	~~641~~930	$	—		$	—		$	~~129~~186,~~101~~343
Other	~~240~~	359		—	—	~~3,700~~	5,758		~~(3,005~~	(4,573)	)	~~935~~	1,544
Total revenues	~~128,700~~	185,772		~~641~~	930	~~3,700~~	5,758		~~(3,005~~	(4,573)	)	~~130,036~~	187,887
EXPENSES:
Lease operating expense	~~36,020~~	53,450		30	40	~~1,603~~	2,388		—	—		~~37,653~~	55,878
Production and property taxes	~~3,967~~	5,928		15	17	24	185		—	—		~~4,006~~	6,130
Transportation expense	~~2,917~~	4,437		6	10	—	—		~~(2,817~~	(4,290)	)	~~106~~	157
Depletion, depreciation and amortization	~~22,503~~	34,027		52	79	~~415~~	623		—	—		~~22,970~~	34,729
Impairment of oil and gas properties	~~817~~	817		—	—	—	—		—	—		~~817~~	817
Accretion of asset retirement obligations	~~1,140~~	1,726		62	94	21	32		—	—		~~1,223~~	1,852
General and administrative, net of amounts capitalized	~~17,579~~	18,873		1	1	~~260~~	413		~~(188~~	(283)	)	~~17,652~~	19,004
Total expenses	~~84,943~~	119,258		~~166~~	241	~~2,323~~	3,641		~~(3,005~~	(4,573)	)	~~84,427~~	118,567
Income (loss) from operations	43,757			475		1,377			—			45,609
Income from operations		66,514			689		2,117			—			69,320
FINANCING COSTS AND OTHER:
Interest expense, net	~~29,210~~	44,378		—	—	~~(2,919~~	(4,452)	)	—	—		~~26,291~~	39,926
Amortization of deferred loan costs	~~1,696~~	2,583		—	—	—	—		—	—		~~1,696~~	2,583
Commodity derivative losses (gains), net	16,815			—		—			—			16,815
Loss on extinguishment of debt		—			—		—			—			—
Total financing costs and other	47,721			—		(2,919		)	—			44,802
Commodity derivative losses (gains), net		(13,521)			—		—			—			(13,521)
Equity in subsidiary income	2,958			—		—			(2,958		)	—
Total financing costs and other		33,440			—		(4,452)			—			28,988
Income (loss) before income taxes	(1,006		)	475		4,296			(2,958		)	807
Equity in subsidiary income		4,501			—		—			(4,501)			—
Income tax provision (benefit)	(1,813		)	180		1,633			—			—
Income (loss) before income taxes		37,575			689		6,569			(4,501)			40,332
Net income (loss)	$	807		$	295	$	2,663		$	(2,958	)	$	807
Income tax provision (benefit)		(2,757)			262		2,496			(1)			—
Net income (loss)	$	40,332		$	427	$	4,073		$	(4,500)		$	40,332

21 23

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

~~SIX~~ NINE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, 2015 (Unaudited)

(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries		Non-Guarantor Subsidiary			Eliminations			Consolidated
				Guarantor		Non-‑Guarantor
	Venoco, Inc.			Subsidiaries		Subsidiary			Eliminations			Consolidated
REVENUES:
Oil and natural gas sales	$	3849,~~753~~244		$	~~313~~468	$	—		$	—		$	3949,~~066~~712
Other	~~248~~	375		—	—	~~4,447~~	5,849		~~(3,473~~	(4,494)	)	~~1,222~~	1,730
Total revenues	~~39,001~~	49,619		~~313~~	468	~~4,447~~	5,849		~~(3,473~~	(4,494)	)	~~40,288~~	51,442
EXPENSES:
Lease operating expense	~~26,613~~	38,874		27	34	~~1,498~~	2,185		—	—		~~28,138~~	41,093
Production and property taxes	~~4,088~~	4,672		1	2	70	232		—	—		~~4,159~~	4,906
Transportation expense	~~3,355~~	4,321		17	26	—	—		~~(3,279~~	(4,200)	)	93	147
Depletion, depreciation and amortization	~~15,585~~	19,609		52	78	~~418~~	628		—	—		~~16,055~~	20,315
Impairment of oil and gas properties	~~146,030~~	337,830		—	—	—	—		—	—		~~146,030~~	337,830
Accretion of asset retirement obligations	~~933~~	1,420		68	102	10	14		—	—		~~1,011~~	1,536
General and administrative, net of amounts capitalized	~~13,667~~	19,532		—	—	~~234~~	358		~~(194~~	(293)	)	~~13,707~~	19,597
Total expenses	~~210,271~~	426,258		~~165~~	242	~~2,230~~	3,417		~~(3,473~~	(4,493)	)	~~209,193~~	425,424
Income (loss) from operations	(171,270		)	148		2,217			—			(168,905		)
Income from operations		(376,639)			226		2,432			(1)			(373,982)
FINANCING COSTS AND OTHER:
Interest expense, net	~~34,662~~	55,121		—	—	~~(3,325~~	(5,073)	)	—	—		~~31,337~~	50,048
Amortization of deferred loan costs	~~2,087~~	3,060		—	—	—	—		—	—		~~2,087~~	3,060
Loss (gain) on extinguisment of debt	(67,515		)	—		—			—			(67,515		)
Loss (gain) on extinguishment of debt		(67,515)			—		—			—			(67,515)
Commodity derivative losses (gains), net	~~(3,200~~	(24,639)	)	—	—	—	—		—	—		~~(3,200~~	(24,639)	)
Total financing costs and other	~~(33,966~~	(33,973)	)	—	—	~~(3,325~~	(5,073)	)	—	—		~~(37,291~~	(39,046)	)
Equity in subsidiary income	~~3,528~~	4,794		—	—	—	—		~~(3,528~~	(4,794)	)	—	—
Income (loss) before income taxes	~~(133,776~~	(337,872)	)	~~148~~	226	~~5,542~~	7,505		~~(3,528~~	(4,795)	)	~~(131,614~~	(334,936)	)
Income tax provision (benefit)	~~(2,162~~	(2,938)	)	56	86	~~2,106~~	2,852		—	—		—	—
Net income (loss)	$	(~~131~~334,~~614~~934)	)	$	92140	$	34,~~436~~653		$	(34,~~528~~795)	)	$	(~~131~~334,~~614~~936)	)

22 24

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE ~~SIX~~NINE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, 2014 (Unaudited)

(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations		Consolidated
							Non-
				Guarantor			Guarantor
	Venoco, Inc.			Subsidiaries			Subsidiary			Eliminations		Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	2526,~~727~~172		$	~~617~~885		$	47,~~513~~563		$	—	$	3034,~~857~~620
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties	~~(51,888~~	(75,774)	)	2	9		~~(160~~	(71)	)	—	—	~~(52,046~~	(75,836)	)
Acquisitions of oil and natural gas properties	~~(16~~	(38)	)	—	—		—	—		—	—	~~(16~~	(38)	)
Expenditures for property and equipment and other	~~(295~~	(512)	)	—	—		—	—		—	—	~~(295~~	(512)	)
Net cash provided by (used in) investing activities	(52,199		)	2			(160		)	—		(52,357		)
Proceeds from sale of oil and natural gas properties		—			—			—			—		—
Net cash provided by (used in) investing activities		(76,324)			9			(71)			—		(76,386)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from (repayments of) intercompany borrowings	~~4,972~~	8,386		~~(619~~	(894)	)	~~(4,353~~	(7,492)	)	—	—	—	—
Proceeds from long-term debt	~~132,000~~	182,000		—	—		—	—		—	—	~~132,000~~	182,000
Principal payments on long-term debt	~~(107,000~~	(122,000)	)	—	—		—	—		—	—	~~(107,000~~	(122,000)	)
Payments for deferred loan costs	~~(358~~	(371)	)	—	—		—	—		—	—	~~(358~~	(371)	)
Dividend paid to Denver Parent Corporation	~~(3,905~~	(3,905)	)	—	—		—	—		—	—	~~(3,905~~	(3,905)	)
Net cash provided by (used in) financing activities	~~25,709~~	64,110		~~(619~~	(894)	)	~~(4,353~~	(7,492)	)	—	—	~~20,737~~	55,724
Net increase (decrease) in cash and cash equivalents	~~(763~~	13,958	)	—	—		—	—		—	—	~~(763~~	13,958	)
Cash and cash equivalents, beginning of period	~~828~~	828		—	—		—	—		—	—	~~828~~	828
Cash and cash equivalents, end of period	$	6514,786		$	—		$	—		$	—	$	6514,786

23 25

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE ~~SIX~~NINE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, 2015 (Unaudited)

(in thousands)

	Venoco, Inc.			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations		Consolidated
							Non-
				Guarantor			Guarantor
	Venoco, Inc.			Subsidiaries			Subsidiary			Eliminations		Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	4(8,~~671~~053)		$	~~268~~414		$	68,~~253~~383		$	—	$	~~11,192~~744
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties	~~(7,246~~	(16,076)	)	~~(50~~	(49)	)	—	—		—	—	~~(7,296~~	(16,125)	)
Acquisitions of oil and natural gas properties	~~(12~~	(15)	)	—	—		—	—		—	—	~~(12~~	(15)	)
Expenditures for property and equipment and other	~~(119~~	(169)	)	—	—		—	—		—	—	~~(119~~	(169)	)
Proceeds provided by sale of oil and gas properties	1,811			—			—			—		1,811
Proceeds from sale of oil and natural gas properties		1,846			—			—			—		1,846
Net cash provided by (used in) investing activities	~~(5,566~~	(14,414)	)	~~(50~~	(49)	)	—	—		—	—	~~(5,616~~	(14,463)	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from (repayments of) intercompany borrowings	~~6,471~~	8,748		~~(218~~	(365)	)	~~(6,253~~	(8,383)	)	—	—	—	—
Proceeds from long-term debt	~~340,000~~	340,000		—	—		—	—		—	—	~~340,000~~	340,000
Principal payments on long-term debt	~~(155,000~~	(155,000)	)	—	—		—	—		—	—	~~(155,000~~	(155,000)	)
Debt issuances cost	(12,427		)	—			—			—		(12,427		)
Payments for deferred loan costs		(14)			—			—			—		(14)
Increase in restricted cash	(79,595		)	—			—			—		(79,595		)
Debt Issuance Costs		(12,426)			—			—			—		(12,426)
Net cash provided by (used in) financing activities	99,449			(218		)	(6,253		)	—		92,978
Increased in restricted cash		(79,588)			—			—			—		(79,588)
Net increase (decrease) in cash and cash equivalents	98,554			—			—			—		98,554
Dividend paid to Denver Parent Corporation		—			—			—			—		—
Cash and cash equivalents, beginning of period	15,455			—			—			—		15,455
Net cash provided by (used in) financing activities		101,720			(365)			(8,383)			—		92,972
Cash and cash equivalents, end of period	$	114,009		$	—		$	—		$	—	$	114,009
Net increase (decrease) in cash and cash equivalents		79,253			—			—			—		79,253
Cash and cash equivalents, beginning of period		15,455			—			—			—		15,455
Cash and cash equivalents, end of period	$	94,708		$	—		$	—		$	—	$	94,708

24 26

Table of Contents

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

The following discussion and analysis should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in the Venoco / DPC Annual Report on Form 10-K for the year ended December 31, 2014 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~~ Our ~~Developments~~financial results depend on many factors, but are largely driven by the volume of our oil production and the price that we receive for that production. Since the latter half of 2014 there has been a substantial decline in oil prices and our production has been significantly impacted by a shut-down of the third-party common carrier pipeline that transports oil from Platform Holly.

On Material ~~May 19,~~Trends 2015, the third-party common carrier pipeline that transports oil production from Platform Holly in the South Ellwood field ruptured, resulting in a spill near Refugio Beach State Park. We have temporarily halted production activities at Platform Holly in response to the incident. The affected pipeline, in Santa Barbara County, is currently inoperable due to the spill and related ongoing repairs. Until the required metallurgical and root cause analysis are completed the pipeline operator has stated that it is unable to address the timing of returning the pipeline to service. The results of the analysis are expected in late August 2015. However, the operator’s current forecasts estimate that the pipeline will be shut down for the remainder of 2015. As a result we are currently in the process of evaluating alternatives that would allow us to return to production. In order to minimize full-year 2015 downtime, we elected to move our annual maintenance shutdown at the South Ellwood field from the third quarter of 2015 up to May and June to coincide with the pipeline shutdown.Uncertainties

~~Capital~~ On ~~Expenditures~~May 19, 2015, the third-party common carrier pipeline that transports oil production from Platform Holly in the South Ellwood field ruptured, resulting in a spill near Refugio Beach State Park. The affected pipeline, in Santa Barbara County, is currently inoperable due to the spill and related ongoing repairs. As a result, we have been forced to halt production activities at Platform Holly in response to the incident. The pipeline operator has stated that until the required metallurgical and root cause analyses are completed, it will be unable to address the timing of returning the pipeline to service. We are currently in the process of evaluating alternatives that would allow us to return to production prior to the pipeline returning to service. At the time of this filing, we do not anticipate returning Platform Holly to service in 2015.

As Production afrom ~~result~~Platform Holly accounts for approximately half of the ~~additional~~Company’s ~~financing~~total ~~received~~production inand ~~April~~therefore ~~2015~~ the ~~Company~~shut-down ~~increased~~has ~~its~~had ~~2015~~a ~~capital~~significant ~~budget~~impact ~~from~~on ~~$18~~our ~~million~~operating tocash ~~$33 million~~flows. We ~~The~~have ~~additional~~taken ~~budget~~measures ~~has~~to ~~been~~reduce ~~allocated~~the toexpenses ~~drilling~~associated ~~two~~with ~~wells~~maintaining the platform and the Ellwood on-shore ~~Platform~~facility ~~Gail~~while aswe ~~discussed~~are ~~below.~~not Inproducing, ~~the~~including ~~first~~obtaining ~~half~~permits from the State of ~~2015~~California ~~our~~to ~~development,~~reduce ~~exploitation~~the ~~and~~number ~~exploration~~of ~~capital~~employees ~~expenditures~~required ~~were~~to $8operate.~~3 million~~ However, there are still significant operating expenses associated with ~~approximately~~the ~~$7.0 million~~platform ~~incurred~~and ~~for~~the ~~Southern~~on-shore ~~California~~facility ~~legacy~~that ~~projects~~we must incur while production is shut in.

~~The~~ In ~~aggregate~~the ~~levels~~third quarter of ~~capital~~2014 ~~expenditures~~our ~~for~~application ~~the~~to ~~remainder~~adjust ofthe ~~2015,~~lease ~~and~~line at the ~~allocation~~South ofEllwood ~~those~~field ~~expenditures,~~was ~~are~~deemed ~~dependent~~complete onby athe ~~variety~~California ofState ~~factors,~~Lands ~~including~~Commission ~~changes~~(“CSLC”). inThe ~~commodity~~application ~~prices,~~is ~~permitting~~subject ~~matters,~~to review by the ~~availability~~CSLC ofunder ~~capital~~the ~~resources~~California toEnvironmental ~~fund~~Quality ~~the~~Act ~~expenditures~~(“CEQA”). ~~and~~In ~~changes~~May in2015 ~~our~~CSLC ~~business~~initiated ~~assessments~~efforts asrelating to ~~where~~the ~~our~~environmental ~~capital~~impact ~~can~~review be(“EIR”) ~~most~~and ~~profitably~~related ~~employed.~~report ~~Accordingly,~~as ~~the~~required ~~actual~~by ~~levels~~CEQA. The scope of ~~capital expenditures and~~ the ~~allocation~~EIR ofincludes ~~those~~evaluating ~~expenditures~~major ~~may~~environmental ~~vary~~issues ~~materially~~associated ~~from~~with ~~our~~the ~~estimates.~~adjustment ~~The~~such ~~following~~as ~~summarizes~~hazardous ~~certain~~materials ~~significant~~and ~~aspects~~risk of ~~our~~upset, ~~2015~~air ~~capital~~quality, ~~spending program.~~

In the first half of 2015, we focused our capital spending primarily on operational improvements, regulatory, health, safety and environmental compliance and progressing other long lead-time projects, primarily at our legacy Southern California assets. The aggregate levels of capital expenditures through the first half of 2015 were in line with our budget estimates. 27

In Table ~~the third quarter~~ of 2014 our application to adjust the lease line at the South Ellwood field was deemed complete by the California State Lands Commission (“CSLC”). The application is subject to review by the CSLC under the California Environmental Quality Act (“CEQA”). In the first half of 2015 CSLC initiated efforts relating to the environmental impact review (“EIR”) and related report as required by CEQA. The scope of the EIR includes evaluating a number of project alternatives.Contents

25greenhouse gases and a number of other issues, as well as a number of project alternatives. We anticipate a draft of the EIR to be issued in the first quarter 2016, but it could be longer. Our application may not be granted on the terms we request or at all.

~~Table~~ Operations ~~of Contents~~Update

~~Additionally,~~ South ~~the~~Ellwood EIR will evaluate the major environmental issues associated with the adjustment such as hazardous materials and risk of upset, air quality, greenhouse gases and a number of other issues. We anticipate a draft of the EIR to be issued in the fall of 2015, but it could be longer. Our application may not be granted on the terms we request or at all.

In As ~~the~~discussed ~~Sockeye~~above ~~field,~~Platform weHolly ~~focused~~has ~~capital~~been ~~spending~~ shut-in due to the ~~first~~rupture ~~half~~that ofoccurred on the third-party common carrier pipeline in May 2015. In onresponse ~~advancing~~to ~~long~~the ~~lead~~shut-~~time~~in ~~projects~~the ~~and~~Company ~~operational~~has ~~improvements. As~~tried ato ~~result~~take advantage of the ~~recently~~downtime ~~completed~~by ~~financing~~performing ~~transactions,~~the wenormal ~~have~~annual ~~decided~~maintenance towhich ~~proceed~~usually ~~with~~requires ~~drilling~~a ~~activities~~three inweek ~~2015. We~~shut-down ~~are~~of ~~currently~~the ~~drilling~~platform. The ~~one~~Company ~~well~~also ~~off~~accelerated a number of ~~Platform~~items ~~Gail~~that ~~into~~were ~~the~~scheduled M2to ~~zone. Additionally,~~be weperformed ~~are~~in ~~preparing~~2016 in an ~~engineering~~effort ~~program~~to ~~for~~minimize ~~the~~downtime ~~drilling~~as ofmuch ~~one~~as ~~additional~~possible ~~well~~when ~~into~~ the M2pipeline ~~zone~~returns atto ~~Platform Gail~~operation.

~~With~~ Capital ~~respect~~expenditures toat ~~our~~South ~~reversionary~~Ellwood ~~interest~~were ~~in the Hastings Complex CO2 project being developed by Denbury, in January 2013 Venoco notified Denbury that it was invoking the arbitration provisions contained in contracts relating to the project~~$0.9 ~~The~~million ~~dispute~~and ~~involves the calculation of the cost of CO2 delivered to the Hastings Complex which is used in Denbury’s enhanced oil recovery operations~~$1.6 ~~Venoco~~million, ~~believes that Denbury has materially overcharged the payout account~~ for the ~~cost~~three ~~of CO2~~ and ~~the~~nine ~~cost~~months ofended ~~transporting~~September it2015, ~~to the Hastings Complex~~respectively. We Inhave ~~December 2013~~focused aour ~~three~~capital ~~member~~spending ~~arbitration~~at ~~panel~~South ~~ruled~~Ellwood ~~unanimously~~primarily ~~that~~on ~~Venoco’s~~operational ~~interpretation~~improvements, ofregulatory, ~~the contracts was correct. In January 2014~~health, ~~Denbury requested that the arbitration panel modify its decision in a way that could increase the cost of CO2 delivered to the Hastings Complex. In March 2014~~safety, ~~the arbitration panel affirmed its decision consistent with Venoco’s position. In late March 2014 Denbury filed a petition in Harris County Texas District Court to modify~~ and ~~vacate~~environmental ~~the arbitration award. In May 2014 Venoco filed an opposition to Denbury’s petition and requested that the Texas District Court confirm the arbitration award. On February 11~~compliance, ~~2015~~as ~~the~~well ~~District~~as ~~Court~~progressing ~~granted~~other ~~Venoco’s~~long-lead ~~motion~~time ~~to confirm the arbitration award~~projects. ~~In March 2015, Denbury filed a motion for a new trial with the District Court which was denied. Denbury appealed the case to the Texas Court of Appeals in May 2015.~~

~~Trends~~ Sockeye ~~Affecting our Results of Operations~~Field

~~Oil~~ As ~~and~~a ~~Natural~~result ~~Gas~~of ~~Prices. Historically,~~the ~~prices~~financing received ~~for~~in ~~our oil and natural gas production have been volatile and unpredictable~~April, ~~and~~the ~~that~~Company ~~volatility~~decided ~~is expected~~ to ~~continue.~~proceed ~~Changes~~with ina ~~the~~drilling ~~market~~program ~~prices~~at ~~for~~Platform ~~oil~~Gail. Two ~~directly~~wells ~~impact~~were ~~many~~drilled ~~aspects~~in ofto ~~our~~the ~~business,~~M2 ~~including~~zone ~~our~~in ~~financial~~the ~~condition,~~first ~~revenues,~~nine ~~results~~months of ~~operations,~~2015. The ~~liquidity,~~first ~~rate~~well ofwas ~~growth,~~completed ~~carrying~~in ~~value~~September ~~of our properties~~ and ~~value~~the ofsecond ~~our~~well ~~proved~~was ~~reserves,~~completed ~~all of which depend~~ in ~~part~~October. The ~~upon~~Company ~~those~~is ~~prices.~~continuing Weto ~~have~~perform ~~sold~~a ~~all~~number of ~~our~~additional ~~properties~~downhole ~~that~~engineering ~~produce~~operations ~~primarily natural gas and therefore expect~~ to ~~have~~maximize ~~minimal~~the ~~exposure~~productive tocapabilities ~~changes~~of ineach ~~natural gas prices for the foreseeable future~~well.

We Capital ~~follow~~expenditures at the ~~full~~Sockeye ~~cost~~Field ~~method~~were of$10.0 ~~accounting~~million ~~for our oil~~ and ~~gas properties~~$11. In1 ~~the second quarter of 2015~~million, for the ~~results~~three ~~of our full cost “ceiling test” required us to recognize a before tax impairment of our oil~~ and ~~gas~~nine ~~properties~~months ofended ~~$146~~September ~~million. While this impairment did not impact cash flow from operating activities~~2015, ~~it did reduce our earnings~~respectively. We The ~~will~~majority ~~likely be required to recognize additional impairments~~ of ~~oil~~the ~~and~~capital ~~gas~~spending ~~properties~~at inthe ~~future~~field ~~periods~~was ifprimarily weon ~~continue~~drilling ~~to experience an extended period of low commodity prices, which will result in a downward adjustment to our estimated proved reserves~~ and ~~the~~completion ~~associated present value of estimated future net revenues, or if we incur actual development~~ costs inrelated ~~excess~~to ~~of the estimated costs used in preparing~~ our ~~reserve~~2015 ~~reports~~drilling program.

We Trends ~~employ~~Affecting aour ~~hedging~~Results ~~strategy designed to reduce the variability in cash flows resulting from changes in commodity prices. As~~ of June 30, 2015, we had hedge contract floors covering 4,595 barrels of oil per day for 2015. We have also secured hedge contracts for portions of our 2016 production. See “Quantitative and Qualitative Disclosures About Market Risk—Commodity Derivative Transactions” for further details concerning our hedging activities.Operations

~~Production. Average~~ Our ~~BOE~~revenue, ~~per~~profitability ~~day~~and ~~produced~~future ingrowth ~~the~~rate ~~first~~depend ~~half~~substantially ofon ~~2015~~factors ~~was~~beyond 5our control,~~285~~ ~~compared~~such toas 6economic,~~612~~ ~~for~~political ~~the~~and ~~fourth~~regulatory ~~quarter~~developments, ofas ~~2014.~~well ~~The~~as ~~reduction~~competition infrom ~~production~~other issources ~~due the sale~~ of ~~our~~energy. ~~West~~Oil ~~Montalvo properties~~ and ~~the~~natural ~~effect~~gas ofprices ~~shutting~~historically inhave ~~Platform~~been ~~Holly~~volatile asand amay ~~result~~fluctuate ofwidely in the ~~pipeline spill~~future. ~~Our~~ ~~2015~~Sustained ~~capital~~periods ~~spending~~of ~~has~~low ~~been~~prices ~~allocated~~for ~~approximately~~oil ~~92%~~or tonatural ~~our~~gas ~~legacy~~could ~~Southern~~materially ~~California fields~~ and 8%adversely toaffect our ~~onshore~~financial ~~Monterey~~position, ~~shale~~our ~~program.~~results ~~In light~~ of ~~current~~operations, ~~commodity prices and~~ our ~~need~~cash ~~to preserve liquidity~~flows, wethe ~~have~~quantities ~~substantially~~of ~~reduced~~oil ~~our~~and ~~capital~~natural ~~expenditure~~gas ~~budget~~reserves ~~for~~that ~~2015~~we ~~relative~~can toeconomically ~~prior~~produce ~~years. Due to these factors~~ and ~~natural~~our ~~production~~access ~~declines, we expect production~~ to ~~decline year over year from 2014~~capital.

~~Lease~~ We ~~Operating~~generally ~~Expenses~~hedge a portion of our expected future oil and gas production to reduce our exposure to fluctuations in commodity price. ~~Lease~~ ~~operating~~By ~~expenses~~removing ~~(“LOE”)~~a portion of ~~$29.40~~commodity ~~per~~price ~~BOE~~volatility, ~~for~~we ~~the~~expect ~~first~~to ~~half~~reduce some of ~~2015~~the ~~were~~variability ~~higher~~in ~~than~~ our ~~full~~cash ~~year~~flow ~~2014~~from ~~results~~operations. ofSee ~~$26~~“Item 3.77 ~~per~~— ~~BOE~~Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Exposure” for discussion of our hedging and hedge positions. We ~~Lower~~plan ~~production~~to atcontinue our strategy of hedging the ~~South~~risks ~~Ellwood~~associated ~~field~~with ~~contributed~~commodity toprice ~~higher~~volatility; ~~LOE~~however, ~~per~~given ~~BOE~~the ~~costs~~current low commodity price environment, aswe ~~did~~may limit the ~~sale~~extent of ~~the~~our ~~West~~hedging ~~Montalvo~~program ~~field~~in the near-term.

26 Like all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from any given well is expected to decline. As a result, oil and natural gas exploration and production companies deplete their asset base with each unit of oil or natural gas they produce. We attempt to overcome this natural production decline by developing additional reserves through our drilling operations, acquiring additional reserves and production and implementing secondary recovery techniques. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production. We will maintain our focus on the capital investments necessary to produce our reserves as well as to add to our reserves through drilling and acquisitions. Our

~~Table of Contents~~ 28

~~Property~~ Table ~~and Production Taxes. Property and production taxes~~ of $4.35 per BOE for the first half of 2015 were higher than our full year 2014 results of $2.82 per BOE. We expect our 2015 property and production taxes to be higher on a per BOE basis than they were in 2014. Our ad valorem tax expense is highly sensitive to drilling results and the estimated present value of future net cash flows from new wells, and may be volatile in the future.Contents

~~General~~ability ~~and~~to ~~Administrative~~make ~~Expenses. General and administrative expenses were $14.32 per BOE (excluding non-cash share-based compensation charges of $0.18 per BOE) for~~ the ~~first~~necessary ~~half~~capital ofexpenditures ~~2015~~is ~~compared~~dependent toon ~~$8.39 per BOE for the full year 2014 (excluding non-~~cash ~~share-based~~flow ~~compensation~~from ~~decreases~~operations ofas ~~$1.01~~well ~~per~~as ~~BOE). During 2014 we implemented a reduction in work force program to reduce~~ our ~~overhead~~ability to beobtain ~~more~~additional ~~reflective~~debt ~~of the asset base we have following the Sacramento Basin~~ and ~~West~~equity ~~Montalvo asset sales~~financing. ~~Excluding~~That ~~share-based~~ability ~~compensation~~can ~~charges and certain one-time charges, we expect our 2015 G&A costs to~~ be ~~less~~limited ~~than~~by ~~they~~many ~~were in 2014~~factors, ~~but,~~including onthe acost ~~per~~and ~~BOE~~terms ~~basis,~~of tosuch ~~increase~~capital inand ~~2015~~operational ~~compared to 2014 due to our lower expected production in 2015~~considerations.

~~Depreciation,~~ Results ~~Depletion and Amortization (DD&A). DD&A for the first half~~ of ~~2015 was $16.78 per BOE compared to $16.31 per BOE for the full year 2014. We expect our 2015 DD&A to be similar on a per BOE basis compared to our 2014 results.~~Operations

~~Commodity~~ The ~~Derivative~~following ~~Gains~~table ~~and~~reflects ~~Losses. We~~the docomponents ~~not~~of ~~account~~our ~~for~~oil ~~commodity~~and ~~derivative~~natural ~~contracts~~gas asproduction ~~cash~~and ~~flow~~sales ~~hedges.~~prices, ~~Commodity derivative gains~~ and ~~losses~~our ~~include~~operating ~~settlements of commodity derivative contracts~~revenues, ~~changes~~costs ~~in fair value of open commodity derivative contracts~~ and ~~amortization of derivative premiums. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled. Therefore~~expenses, wefor ~~expect our net income to reflect~~ the ~~volatility~~periods ~~of commodity price forward markets~~indicated. ~~Our~~No ~~cash~~pro ~~flows~~forma ~~will~~adjustments ~~only~~have bebeen ~~affected~~made ~~upon~~for ~~settlement of~~ the ~~transactions~~acquisitions atand ~~the~~divestitures ~~current market prices at that time. Cash settlement~~ of ~~derivative~~oil ~~instruments represents the difference between the strike prices in contracts settled during the period~~ and ~~the~~natural ~~ultimate~~gas ~~settlement~~properties, ~~prices.~~which ~~Payments actually due to or from counterparties on these derivatives~~ will ~~typically~~affect ~~be offset by corresponding changes in prices ultimately received from~~ the ~~sale~~comparability of ~~our production. We have incurred significant commodity derivative gains and losses in recent periods and may continue to incur these types of gains and losses in~~ the ~~future~~data below. The

Income Tax Provision (Benefit). We incurred losses before income taxes in 2008, 2009, and 2012, as well as tax losses in each of the tax years from 2008 through 2013. These losses and expected future tax 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, 2014 and June 30, 2015 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; 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. 29

~~Our~~ Table ~~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.Contents

~~Results~~information set forth below is not necessarily indicative of ~~Operations~~future results. Except for the items identified below as being specific to Venoco or DPC, all information shown is for both companies.

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				Quarter		Nine Months Ended				YTD
	September 30,				Comparison		September 30,				Comparison
Venoco	2014		2015		$ Change		2014		2015		$ Change
REVENUES:
Oil and natural gas sales	$	57,242	$	10,646	$	(46,596)	$	186,343	$	49,712	$	(136,631)
Other		609		508		(101)		1,544		1,730		186
Total revenues		57,851		11,154		(46,697)		187,887		51,442		(136,445)
EXPENSES:
Lease operating expense		18,225		12,955		(5,270)		55,878		41,093		(14,785)
Production and property taxes		2,124		747		(1,377)		6,130		4,906		(1,224)
Transportation expense		51		54		3		157		147		(10)
Depletion, depreciation and amortization		11,759		4,260		(7,499)		34,729		20,315		(14,414)
Impairment		—		191,800		191,800		817		337,830		337,013
Accretion of asset retirement obligations		629		525		(104)		1,852		1,536		(316)
General and administrative, net of amounts capitalized		1,352		5,890		4,538		19,004		19,597		593
Total expenses		34,140		216,231		182,091		118,567		425,424		306,857
Income (loss) from operations		23,711		(205,077)		(228,788)		69,320		(373,982)		(443,302)
FINANCING COSTS AND OTHER:
Interest expense, net		13,635		18,711		5,076		39,926		50,048		10,122
Amortization of deferred loan costs		887		973		86		2,583		3,060		477
Loss (gain) on extinguishment of debt		—		—		—		—		(67,515)		(67,515)
Commodity derivative losses (gains), net		(30,336)		(21,439)		8,897		(13,521)		(24,639)		(11,118)
Total financing costs and other		(15,814)		(1,755)		14,059		28,988		(39,046)		(68,034)
Net income (loss)	$	39,525	$	(203,322)	$	(242,847)	$	40,332	$	(334,936)	$	(375,268)
DPC
General and administrative, net of amounts capitalized	$	1,403	$	5,890	$	4,487	$	19,394	$	19,666	$	272
Interest expense, net		22,613		28,885		6,272		65,502		79,158		13,656

Production Volume(1):
Oil (MBbls)		642		250		(392)		1,978		1,161		(817)
Natural gas (MMcf)		202		73		(129)		702		351		(351)
MBOE(2)		676		262		(414)		2,095		1,220		(875)
Daily Average Production Volume:
Oil (Bbls/d)		6,978		2,717		(4,261)		7,245		4,253		(2,992)
Natural gas (Mcf/d)		2,196		793		(1,403)		2,571		1,286		(1,285)
BOE/d(2)		7,344		2,849		(4,495)		7,674		4,467		(3,207)
Oil Price per Bbl Produced (in dollars):
Realized price	$	87.84	$	42.03	$	(45.81)	$	92.74	$	42.86	$	(49.88)
Realized commodity derivative gain (loss)		(2.14)		67.36		69.50		(4.77)		50.76		55.53
Net realized price	$	85.70	$	109.39		23.69	$	87.97	$	93.62		5.65
Natural Gas Price per Mcf Produced (in dollars):
Realized price	$	4.98	$	3.33	$	(1.65)	$	5.51	$	3.17	$	(2.34)
Realized commodity derivative gain (loss)		0.11		—		(0.11)		0.03		—		(0.03)
Net realized price	$	5.09	$	3.33		(1.76)	$	5.54	$	3.17		(2.37)
Expense per BOE:
Lease operating expenses	$	26.96	$	49.45	$	22.49	$	26.67	$	33.68	$	7.01
Production and property taxes		3.14		2.85		(0.29)		2.93		4.02		1.10
Transportation expenses		0.08		0.21		0.13		0.07		0.12		0.05
Depletion, depreciation and amortization		17.39		16.26		(1.14)		16.58		16.65		0.07
Venoco:
General and administrative expense, net(3)	$	2.00	$	22.48	$	20.48	$	9.07	$	16.06	$	6.99
Interest expense, net		20.17		71.42		51.25		19.06		41.02		21.97
Denver Parent Corporation:
General and administrative expense, net(3)	$	2.08	$	22.48	$	20.41	$	9.26	$	16.12	$	6.86
Interest expense, net		33.45		110.25		76.80		31.27		64.88		33.62

	Three Months Ended June 30,					Six Months Ended June 30,
	2014			2015		2014			2015
Production Volume(1):
Oil (MBbls)	681			396		1,336			911
Natural gas (MMcf)	231			118		500			278
MBOE(2)	720			416		1,419			957
Daily Average Production Volume:
Oil (Bbls/d)	7,484			4,337		7,381			5,028
Natural gas (Mcf/d)	2,538			1,303		2,762			1,544
BOE/d(2)	7,907			4,554		7,841			5,285
Oil Price per Bbl Produced (in dollars):
Realized price	$	95.63		$	49.50	$	95.10		$	43.09
Realized commodity derivative gain (loss) (4)	(6.65		)	68.76		(6.03		)	46.21
Net realized price	$	88.98		$	118.26	$	89.07		$	89.30
Natural Gas Price per Mcf (in dollars):
Realized price	$	5.35		$	3.04	$	5.73		$	3.12
Realized commodity derivative gain (loss)	—			—		—			—
Net realized price	$	5.35		$	3.04	$	5.73		$	3.12
Expense per BOE:
Lease operating expenses	$	25.26		$	31.75	$	26.53		$	29.40
Property and production taxes	3.15			4.87		2.82			4.35
Transportation expenses	0.07			0.11		0.07			0.10
Depreciation, depletion and amortization	16.38			17.39		16.19			16.78
Venoco:
General and administrative expense, net(3)	12.49			16.92		12.44			14.32
Interest expense	18.54			47.90		18.53			32.75
Denver Parent Corporation:
General and administrative expense, net(3)	12.60			12.43		12.68			14.39
Interest expense	30.23			71.13		30.22			52.53

(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 and oil pipeline sales nominations.

27(2) BOE is determined using the ratio of one barrel of oil or natural gas liquids to six Mcf of natural gas.

~~Table of Contents~~ 30

~~(1) Amounts~~ Table ~~shown~~of 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 and oil pipeline sales nominations.Contents

(23) ~~BOE~~ isNet ~~determined using the ratio~~ of ~~one~~amounts ~~barrel of oil or natural gas liquids to six Mcf of natural gas~~capitalized.

~~(3) Net~~ Comparison of ~~amounts~~Quarter ~~capitalized.~~Ended September 30, 2015 to Quarter Ended September 30,2014 and Nine Months Ended September 30,2015 to Nine Months Ended September 30,2014

Oil and Natural Gas Sales – Third quarter (4“Q3”) ~~Includes~~ ~~proceeds~~2014 ~~from~~to ~~the~~Q3 ~~unwinding~~2015 ofdecreased ~~our~~81%, ~~2016~~year ~~derivative~~to ~~contract~~date ~~with~~(“YTD”) ~~ABN~~2014 ~~AMRO~~vs ofYTD ~~$15.6~~2015 ~~million.~~decreased 73% due to the:

~~Comparison~~· ofSubstantial ~~Quarter~~decline ~~Ended~~in ~~June 30,~~commodity ~~2015~~prices; ~~to Quarter Ended June 30, 2014~~and

~~Oil~~· ~~and~~Decline ~~Natural Gas Sales. Oil and natural gas sales decreased $47.2 million (71%) to $19.3 million~~ in ~~the~~production ~~second quarter of 2015 compared to $66.5 million in the second quarter of 2014. The decrease was~~ due to ~~lower oil and natural gas production, and lower oil prices, as described below.~~:

~~Oil~~o sales decreased by $46.3 million (71%) in the second quarter of 2015 to $19.0 million compared to $65.3 million in the second quarter of 2014. Oil production decreased by 42%, with production of 396 MBbls in the second quarter of 2015 compared to 681 MBbls in the second quarter of 2014. The ~~decrease is due to the~~ sale of ~~our~~ West Montalvo ~~field~~ in the fourth quarter of 2014~~, the effect of shutting in Platform Holly due to the pipeline spill and natural production declines~~. ~~Our average realized price for oil decreased $46.13 per Bbl (48%) from $95.63 per Bbl in the second quarter of 2014 to $49.50 per Bbl in the second quarter of 2015.~~

~~Natural~~o ~~gas sales decreased $0.8 million (67%)~~ Shut-in ~~the second quarter~~ of ~~2015~~Platform toHolly ~~$0.4 million~~since ~~compared~~May ~~to $1.2 million in the second quarter of 2014. Natural gas production decreased by 49% in the second quarter of~~ 2015, ~~with production of 118 MMcf compared to 231 MMcf in the second quarter of 2014. The decrease is primarily~~ due to the ~~sale~~rupture of ~~our West Montalvo assets and~~ the ~~effect~~third-party ~~of shutting in Platform Holly due to the~~ pipeline ~~spill~~. ~~Our average realized price for natural gas decreased $2.31 per Mcf (43%) from $5.35 per Mcf in the second quarter of 2014 to $3.04 per Mcf in the second quarter of 2015.~~

Other Revenues~~. Other~~ ~~revenues~~- ~~stayed~~Q3 ~~consistent~~2014 atto ~~$0.5~~Q3 ~~million~~2015 ~~for~~decreased ~~both~~17%, ~~the~~YTD ~~second~~2014 ~~quarter~~vs ofYTD 2015 ~~and~~increased ~~the~~12% ~~second~~due ~~quarter~~to ofthe ~~2014.~~following factors:

~~Lease~~· ~~Operating~~The ~~Expenses. Lease~~decrease ~~operating expenses (“LOE”) decreased $5.0 million (27%)~~ in the ~~second~~third quarter ofis ~~2015~~a toresult ~~$13.2 million~~of ~~compared~~a toreduction ~~$18.2 million~~ in the ~~second~~pipeline ~~quarter~~revenue ~~of 2014. The decrease was primarily~~ due to the ~~sale~~shut-in of ~~the~~Platform ~~West~~Holly.

28· The overall increase year to date is due to increased tariff rates for the Carpinteria, Ventura and Las Flores pipelines.

~~Table~~ Lease ofOperating ~~Contents~~Expenses. Q3 2014 to Q3 2015 decreased 29%, YTD 2014 vs YTD 2015 decreased 26% due to the:

~~Montalvo~~· ~~field~~Cost inreduction ~~the~~efforts ~~fourth quarter of 2014,~~ as ~~well as lower lease operating expenses at the South Ellwood and Sockeye fields. On~~ a ~~per~~result ~~unit basis, LOE increased by $6.49 per BOE from $25.26 in the second quarter~~ of ~~2014 to $31.75 in~~ the ~~second~~depressed ~~quarter~~commodity ~~of 2015~~prices.

~~Property~~· ~~and~~Sale ~~Production Taxes. Property and production taxes decreased $0.3 million (13%) in the second quarter~~ of ~~2015 to $2.0 million compared to $2.3 million in the second quarter of 2014. The decrease is primarily due to the sale of the~~ West Montalvo ~~field. On a per BOE basis, property and production taxes increased $1.72 per BOE to $4.87~~ in the ~~second~~fourth quarter of ~~2015 from $3.15 in the second quarter of~~ 2014.

~~Depletion,~~· ~~Depreciation and Amortization (DD&A). DD&A expense decreased $4.6 million (39%) to $7.2 million~~ Shut-in ~~the second quarter~~ of ~~2015~~platform ~~compared~~Holly tosince ~~$11.8 million~~May ~~in the second quarter of 2014~~2015. ~~The~~As ~~decrease~~a ~~was~~result ~~primarily due to the sale~~ of the ~~West Montalvo properties~~ shut-in ~~the~~we ~~fourth~~have ~~quarter~~been ofable ~~2014.~~to ~~DD&A~~reduce ~~expense~~our onvariable acosts ~~per~~associated ~~unit~~with ~~basis~~both ~~increased $1.01 per BOE to $17.39 per BOE for~~ the ~~second~~platform ~~quarter~~and ~~of 2015 compared to $16.38 per BOE for~~ the ~~second~~Ellwood ~~quarter~~on-shore ~~of 2014~~facility.

~~Impairment~~ Property ~~of oil~~ and ~~gas~~Production ~~properties~~Taxes. We Q3 ~~recorded~~2014 ~~pre-tax impairment expense related~~ to ~~our~~Q3 ~~oil~~2015 ~~and~~decreased ~~natural~~65%, ~~gas~~YTD ~~properties~~2014 ~~for~~vs ~~the~~YTD ~~three months ended June 30,~~ 2015 ofdecreased ~~$146~~20% ~~million~~due ~~as a result of our full-cost ceiling test. Under the full cost method, we are subject~~ to ~~quarterly calculations of a ceiling or limitation on~~ the ~~amount~~sale of ~~costs associated with our oil and natural gas properties that can be capitalized in our condensed consolidated balance sheets. The impairment expense for~~ the ~~three~~West ~~months~~Montalvo ~~ended~~field ~~June 30, 2015 was due to a decrease~~ in the ~~value~~fourth ofquarter ~~our proven oil and natural gas reserves as a result~~ of ~~an extended period of low commodity prices. In~~ 2014 weand ~~recorded~~lower anproduction ~~impairment~~and ofproperty ~~$0.8~~assessments ~~million~~at ~~related~~South toEllwood ~~the~~as ~~abandonment~~ of ~~further~~January ~~efforts~~1, ~~to evaluate expansion outside the U~~2015.~~S.A.~~

~~Accretion~~ Depletion, ofDepreciation ~~Abandonment~~and ~~Liability~~Amortization (DD&A). ~~Accretion~~ Q3 ~~expense~~2014 to Q3 2015 decreased ~~$0.1 million~~64%, ~~(17~~YTD 2014 vs YTD 2015 decreased 42%) due to ~~$0.5 million~~the reduction in the ~~second~~Company’s ~~quarter~~asset ofbase ~~2015~~from ~~compared~~the tosale ~~$0.6 million~~of West Montalvo properties in the ~~second~~fourth quarter of 2014 and ceiling test impairments in 2015.

~~General~~ Impairment of oil and ~~Administrative~~gas ~~(G&A)~~properties. ~~The~~We ~~following~~recorded ~~table~~pre-tax ~~summarizes~~impairment expense related to our oil and natural gas properties of $191.8 million and $337.8 million for the ~~components~~three months ended and nine months ended September 30, 2015, respectively, as a result of ~~Venoco’s~~our ~~general~~full-cost ceiling test. Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of costs associated with our oil and ~~administrative~~natural gas properties that can be capitalized in our condensed consolidated balance sheets. The impairment expense ~~incurred~~for ~~during~~both the quarter ended and year to date September 30, 2015 was due to a decrease in the value of our proven oil and natural gas reserves as a result of an extended period of low commodity prices. We will likely be required to recognize additional impairments of oil and gas properties in future periods ~~indicated~~if (we continue to experience an extended period of low commodity prices, which will result in ~~thousands):~~a downward adjustment to our estimated proved reserves and the associated present value of estimated future net revenues, or if we incur actual development costs in excess of the estimated costs used in preparing our reserve reports.

	Three Months Ended June 30,
	2014			2015
General and administrative costs	$	9,364		$	9,985
Share-based compensation costs	473			(395		)
One time general and administrative costs	3,024			—
General and administrative costs capitalized	(3,871		)	(2,553		)
General and administrative expense, net of amounts capitalized	$	8,990		$	7,037

~~Venoco~~ Table ~~G&A expenses decreased $2.0 million (22%) to $7.0 million in the second quarter~~ of 2015 compared to $9.0 million in the second quarter of 2014. The decrease is due to lower employee related G&A costs as a result of the reduction in work force program introduced in 2014 to reduce our overhead to be more reflective of the asset base we have following the Sacramento Basin and West Montalvo asset sales. The 2014 one time G&A cost of $3.0 million was related to the write-off of deferred costs associated with a planned Master Limited Partnership offering which was aborted, and severance costs related to a G&A reduction.Contents

~~Interest~~General ~~Expense. For~~and ~~Venoco,~~Administrative ~~interest expense increased $6.5 million~~ (~~63%~~G&A) ~~to $19~~.~~9 million in the second quarter of 2015 compared to $13.4 million in the second quarter of 2014.~~ The ~~increase~~following ~~was~~table ~~primarily~~summarizes the ~~result~~components of increase in total outstanding borrowings. For DPC, interest expense increased $7.8 million (35%) to $29.6 million in the second quarter of 2015 compared to $21.8 million in the second quarter of 2014. The incremental difference of $9.7 million from Venoco’s ~~total~~general ~~interest~~and ~~expense~~administrative ~~to DPC’s total consolidated interest~~ expense ~~was~~incurred ~~due~~during ~~to interest on DPC’s 12.25% / 13.00% senior PIK toggle notes and~~ the ~~amortization~~periods ofindicated ~~the~~(in ~~bond discount.~~thousands):

Amortization of Deferred Loan Costs. For Venoco, amortization of deferred loan costs increased $0.6 million (71%) to $1.5 million in the second quarter of 2015 compared to $0.9 million in the second quarter of 2014. For DPC, amortization of deferred loan costs increased $0.7 million (63%) to $1.8 million in the second quarter of 2015 compared to $1.1 million in the second quarter of 2014. The increase in amortization of deferred loan costs is related to the costs associated with the new loan agreements which are amortized over the estimated lives of the agreements.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2015		2014		2015
General and administrative costs	$	8,374	$	8,636	$	28,343	$	27,748
Share-based compensation costs		(6,173)		161		(3,055)		(105)
One time general and administrative						3,024		—
General and administrative costs capitalized		(849)		(2,907)		(9,308)		(8,046)
General and administrative expense	$	1,352	$	5,890	$	19,004	$	19,597

~~Loss~~ Venoco’s ~~(gain)~~Q3 on2014 ~~Extinguishment~~to Q3 2015 G&A expense, net of ~~Debt. Venoco~~capitalized ~~recognized~~amounts aincreased ~~$67.5~~significantly ~~million~~due ~~gain~~to onthe ~~extinguishment~~fees associated with the Company’s ongoing restructuring efforts combined with the reduction of ~~debt~~share-based ascompensation acosts ~~result~~in the third quarter of 2014 due to a reduction in the ~~debt~~DPC ~~exchange~~share ~~that~~price. The ~~occurred~~share price reduction in ~~April~~the ~~2015~~third quarter of 2014 also impacted the amount of general and administrative costs that were capitalized.

~~Commodity~~ Venoco’s ~~Derivative~~YTD ~~Losses~~2014 ~~(Gains)~~to YTD 2015 G&A expense, ~~Net~~net of capitalized amounts increased as a result of the fees associated with the Company’s ongoing restructuring efforts offset by costs savings achieved due to the Q3 2014 reduction in force. ~~The~~ ~~following~~As ~~table~~noted ~~sets~~above ~~forth~~the share-based compensation costs in the ~~components~~third quarter of ~~commodity~~2014 ~~derivative~~were ~~losses~~due ~~(gains),~~to ~~net~~a reduction in ~~our~~the ~~condensed~~DPC ~~consolidated~~share ~~statements~~price. The share price reduction in the third quarter of ~~operations~~2014 ~~for~~also impacted the ~~periods~~amount ~~indicated~~of ~~(in thousands):~~general and administrative costs that were capitalized.

	Three Months Ended June 30,
	2014		2015
Realized commodity derivative losses (gains)	$	4,530	$	(26,312	)
Unrealized commodity derivative losses (gains) for changes in fair value	14,380		36,017
Commodity derivative losses (gains), net	$	18,910	$	9,705

Interest Expense. Venoco’s Q3 2014 to Q3 2015 interest expense increased 37%and YTD 2014 vs YTD 2015 increased 25% due to the increase in the total amount of outstanding debt as a result of the April 2015 financing transaction. For DPC, Q3 2014 to Q3 2015 interest expense increased 28% and YTD 2014 vs YTD 2015 increased 21% due to the increase in the total amount of outstanding debt as a result of the PIK interest additions on the DPC’s 12.25% / 13.00% senior PIK toggle notes.

29 Amortization of Deferred Loan Costs. Q3 2014 to Q3 2015 amortization of deferred loan costs increased 10% and YTD 2014 vs YTD 2015 increased 18% due to the costs associated with the new loan agreements which are amortized over the estimated lives of the agreements.

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

Realized commodity derivative gains or losses represent the difference between the strike prices in the contracts settled during the period and the ultimate settlement prices. The realized commodity derivative gains in the second quarter of 2015 reflect the settlement of contracts at prices below the relevant strike prices. Additionally, in the second quarter of 2015 $15.6 million of the realized gain was related to the settlement of our 2016 derivative contract with ABN AMRO. 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.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2015		2014		2015
Realized commodity derivative (gains) losses	$	1,355	$	(16,840)	$	9,410	$	(58,932)
Unrealized commodity derivative (gains) losses for changes in fair value		(31,691)		(4,599)		(22,931)		34,293
Commodity derivative (gains) losses	$	(30,336)	$	(21,439)	$	(13,521)	$	(24,639)

~~Income~~ Realized ~~Tax~~commodity ~~Expense~~derivative ~~(Benefit). Due~~gains toor ~~our~~losses ~~valuation~~represent ~~allowance,~~the ~~there~~difference ~~was~~between nothe ~~income~~strike ~~tax~~prices ~~expense~~in ~~(benefit)~~the ~~recorded~~contracts ~~for~~settled during the ~~quarters~~period ~~ended~~and ~~June 30,~~the ~~2015~~ultimate orsettlement ~~2014~~prices. AsThe ~~long~~realized ascommodity wederivative ~~continue~~gains in the third quarter and year to ~~conclude~~date ~~that~~2015 wereflect ~~have~~the asettlement ~~need~~of ~~for~~contracts aat ~~full~~prices ~~valuation~~below ~~allowance~~the ~~against~~relevant ~~our~~strike ~~net~~prices. ~~deferred~~Unrealized ~~tax~~commodity ~~assets,~~derivative we(gains) ~~likely~~losses ~~will~~represent ~~not~~the ~~have~~change ~~any~~in ~~income~~the ~~tax~~fair ~~expense~~value orof ~~benefit~~our ~~other~~open ~~than~~derivative ~~for~~contracts ~~federal~~from ~~alternative~~period ~~minimum~~to ~~tax~~period. ~~expense~~Derivative orpremiums ~~for~~are ~~state~~amortized ~~income~~over ~~taxes~~the term of the underlying derivative contracts.

~~Net~~ Income Tax Expense (~~Loss~~Benefit). ~~For~~ Due ~~Venoco,~~to ~~net~~our ~~loss~~valuation ~~for~~allowance, ~~the~~there ~~second quarter of 2015~~ was ~~$119.8 million~~no ~~compared~~income totax ~~the~~expense ~~net~~(benefit) ~~loss~~recorded ~~of $8.7 million~~ for the ~~same period in 2014. For DPC, net loss for the second~~ quarter ofand ~~2015~~year ~~was $129.8 million compared~~ to ~~the~~date ~~net~~ended ~~loss of $17.5~~September ~~million~~30, ~~for~~2015 ~~the~~or ~~same period in~~ 2014. ~~The~~As ~~changes~~long ~~between~~as ~~periods~~we ~~are~~continue ~~the~~to ~~result~~conclude ofthat ~~the~~we ~~items discussed above.~~

~~Comparison of Six Months Ended June 30, 2015 to Six Months Ended June 30, 2014~~ 32

~~Oil~~ Table ~~and Natural Gas Sales. Oil and natural gas sales decreased $90.0 million (70%) to $39.1 million in the first half~~ of ~~2015 compared to $129.1 million in the first half of 2014. The decrease was due to lower oil and natural gas production, and lower oil prices, as described below.~~Contents

~~Oil~~have ~~sales~~a ~~decreased~~need byfor ~~$88.0 million~~a ~~(70%)~~full invaluation ~~the~~allowance ~~first~~against ~~half~~our ofnet ~~2015~~deferred totax ~~$38.2 million compared to $126.2 million in the first half of 2014. Oil production decreased by 32%~~assets, ~~with~~we ~~production~~likely ofwill ~~911 MBbls~~not inhave ~~the~~any ~~first~~income ~~half~~tax ofexpense ~~2015~~or ~~compared~~benefit toother ~~1,336~~than MBbls in the first half of 2014. The decrease is primarily due to the sale of our West Montalvo field in the fourth quarter of 2014 and the effect of shutting in Platform Holly due to the pipeline spill and natural declines. Our average realized price for ~~oil~~federal ~~decreased~~alternative ~~$52.01~~minimum ~~per~~tax ~~Bbl~~expense ~~(55%)~~or ~~from $95.10 per Bbl in the first half of 2014 to $43.09 per Bbl~~ for ~~the~~state ~~first~~income ~~half of 2015~~taxes.

~~Natural~~ Net ~~gas~~Income ~~sales~~(Loss). For ~~decreased~~Venoco, ~~$2.0 million~~net ~~(70%)~~loss infor the ~~first~~third ~~half~~quarter of 2015 towas $0203.93 million compared to the net income of $239.95 million infor the ~~first~~same ~~half~~period ofin 2014. ~~Natural~~For ~~gas~~DPC, ~~production~~net ~~decreased~~loss byfor ~~44% in~~ the ~~first~~third ~~half~~quarter of 2015, ~~with~~was ~~production~~$214.1 million ~~of 278 MMcf~~ compared to ~~500 MMcf in~~ the ~~first~~net ~~half~~income of ~~2014~~$30.2 million ~~The~~for ~~decrease is primarily due to~~ the ~~sale~~same ofperiod ~~our~~in ~~West Montalvo assets~~2014. ~~Our~~The ~~average~~changes ~~realized~~between ~~price~~periods ~~for~~are ~~natural gas decreased $2.61 per Mcf (46%) from $5.73 per Mcf in~~ the ~~first~~result ~~half~~ of ~~2014 to $3.12 per Mcf in~~ the ~~first~~items ~~half~~discussed ~~of 2015~~above.

~~Other~~ Liquidity ~~Revenues. Other~~and ~~revenues~~Capital increased $0.3 million (33%) in the first half of 2015 to $1.2 million compared to $0.9 million in the first half of 2014. The increase is primarily due to higher pipeline revenue in the first half of 2015.Resources

~~Lease~~ Venoco’s ~~Operating~~primary ~~Expenses. Lease~~sources ~~operating~~of ~~expenses~~liquidity ~~(“LOE”)~~are ~~decreased~~cash ~~$9.6 million~~generated ~~(25%)~~from inour ~~the~~operations ~~first~~and ~~half~~proceeds offrom ~~2015~~debt ~~to $28~~transactions.~~1 million~~ ~~compared~~In toaddition, ~~$37.7 million~~Venoco inhas ~~the~~commodity ~~first~~derivative ~~half~~positions ofwith ~~2014.~~a ~~The~~net ~~decrease~~asset ~~was~~value ~~primarily~~of ~~due~~$43.8 million toas ~~the~~of ~~sale~~September 30, of2015. ~~the~~If ~~West~~unwound, ~~Montalvo~~these ~~field~~positions incould ~~the~~provide ~~fourth~~an ~~quarter~~additional source of ~~2014,~~liquidity assubject ~~well~~to asthe ~~lower~~commodity ~~lease~~price ~~operating~~environment ~~expenses~~ at the ~~South~~relevant ~~Ellwood~~time. ~~and~~Venoco ~~Sockeye~~unwound ~~fields.~~one Onposition aon ~~per~~April 2, ~~unit basis~~2015, ~~LOE~~which ~~increased~~hedged by1,715 ~~$2.87~~barrels per ~~BOE~~day ~~from~~of ~~$26.53~~our in2016 ~~the~~oil ~~first~~production, ~~half~~receiving proceeds of ~~2014 to~~ $2915.406 million. inDPC’s ~~the~~primary ~~first~~sources ~~half~~ of ~~2015~~liquidity ~~due~~are todistributions ~~lower~~from ~~production~~Venoco atand the ~~South~~issuance ~~Ellwood~~of ~~field~~debt securities.

~~Property~~ Cash and Production Taxes. Property and production taxes increased $0.1 million (3%) in the first half of 2015 to $4.1 million compared to $4.0 million in the first half of 2014. The increase is primarily due to higher property taxes from prior drilling results at our South Ellwood field. On a per BOE basis, property and production taxes increased $1.53 per BOE to $4.35 in the first half of 2015 from $2.82 in the first half of 2014.Flows

Depletion, Depreciation and Amortization (DD&A). DD&A expense decreased $6.9 million (30%) to $16.1 million in the first half of 2015 compared to $23.0 million in the first half of 2014. The decrease was primarily due to the sale of the Montalvo assets in the third


	Venoco, Inc.				Denver Parent Corporation
	Nine Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2015		2014		2015

Cash provided by operating activities	$	34,620	$	744	$	14,712	$	674
Cash provided by (used in) investing activities		(76,386)		(14,463)		(76,386)		(14,463)
Cash provided by (used in) financing activities		55,724		92,972		59,504		92,972

30 Net cash provided by operating activities for Venoco was $0.7 million in the first nine months of 2015 compared to net cash provided by operating activities of $34.6 million in the 2014 period. Cash flows provided by operating activities in the first nine months of 2015 as compared to cash flows provided by operating activities in the nine months of 2014 were impacted by the lower oil prices, and the effect of shutting in Platform Holly due to the pipeline spill.

~~Table~~ Net cash provided by operating activities for DPC was $0.7 million in the first nine months of ~~Contents~~2015 compared to $14.7 million provided in the 2014 period. The difference in the amounts between Venoco and DPC relates to additional DPC amortization of bond discounts and deferred loan costs.

~~quarter~~ Net ofcash ~~2014.~~used ~~DD&A~~in ~~expense~~investing onactivities afor ~~per~~Venoco ~~unit~~and ~~basis~~DPC ~~increased~~was $014.595 million ~~per~~in ~~BOE~~the first nine months of 2015 compared to net cash used by investing activities of $1676.784 ~~per~~million ~~BOE~~in ~~for~~the 2014 period. The primary investing activities in the first ~~half~~nine months of 2015 ~~compared~~were $16.1 million in capital expenditures on oil properties related to our capital expenditure program, partially offset by $161.198 million ~~per~~received ~~BOE~~from ~~for~~the final settlement from the sale of Montalvo and certain other assets. The primary investing activities in the first ~~half~~nine months of 2014 were $76.0 million in capital expenditures on oil properties related to our capital expenditure program.

~~Impairment~~ Net ofcash ~~oil~~provided ~~and~~by ~~gas~~financing ~~properties. We~~activities ~~recorded~~for ~~pre-tax~~Venoco ~~impairment~~was ~~expense~~$93.0 million ~~related~~in tothe ~~our~~first ~~oil~~nine ~~and~~months ~~natural~~of ~~gas~~2015 ~~properties~~compared ~~for~~to ~~the~~net ~~six~~cash ~~months~~provided ~~ended~~by ~~June 30,~~financing ~~2015~~activities of $~~146~~ 55.7 million asduring athe ~~result~~2014 ofperiod. ~~our~~The ~~full-cost~~primary ~~ceiling~~financing ~~test.~~activities ~~Under~~in the ~~full~~first ~~cost~~nine ~~method,~~months ~~we are subject to quarterly calculations~~ of a2015 ~~ceiling~~were orborrowings ~~limitation on the amount~~ of ~~costs~~$340 ~~associated~~million ~~with our oil~~ and ~~natural~~payments ~~gas~~of ~~properties~~$155 ~~that can be capitalized in our condensed consolidated balance sheets~~million. The ~~impairment~~primary ~~expense~~financing ~~for~~activities in the ~~six~~first nine months ~~ended~~of ~~June 30,~~2014 ~~2015~~were ~~was~~net ~~due~~borrowings toof a$60 ~~decrease~~million inon the ~~value~~revolving ofcredit ~~our~~facility ~~proven oil~~ and ~~natural gas reserves as~~ a ~~result~~divided ofpaid anto ~~extended~~DPC ~~period~~ of ~~low commodity prices. In 2014 we recorded an impairment of~~ $03.89 million ~~related to the abandonment of further efforts to evaluate expansion outside the U~~.~~S.A.~~

~~Accretion~~ Capital ofResources ~~Abandonment~~and ~~Liability. Accretion expense decreased $0.2 million (17%) to $1.0 million in the first half of 2015 compared to $1.2 million in the first half of 2014.~~Requirements

~~General~~ Our ~~and~~current ~~Administrative~~2015 ~~(G&A)~~capital expenditure budget is $33 million. ~~The~~ ~~following~~This ~~table~~amount ~~summarizes~~is ~~the~~substantially ~~components~~less than it has been in past years and is reflective of ~~Venoco’s~~current ~~general~~market and ~~administrative~~economic ~~expense~~conditions. ~~incurred~~We ~~during~~previously ~~the~~expected ~~periods~~our ~~indicated~~2015 ~~(in~~capital ~~thousands):~~

	Six Months Ended June 30,
	2014			2015
General and administrative costs	$	19,969		$	19,113
Share-based compensation costs	3,118			(266		)
One time general and administrative	3,024			—
General and administrative costs capitalized	(8,459		)	(5,140		)
General and administrative expense, net of amounts capitalized	$	17,652		$	13,707

~~Venoco~~ Table ~~G&A expenses decreased $4.0 million (23%) to $13.7 million in the first half~~ of 2015 compared to $17.7 million in the first half of 2014. The decrease is due to lower employee related G&A costs as a result of the reduction in work force program introduced in 2014 to reduce our overhead to be more reflective of the asset base we have following the Sacramento Basin and West Montalvo asset sales. Share-based compensation costs decreased $3.4 million due to the 2.0 million unit decrease in the number of units outstanding from 6.0 million in the first half of 2014 to 4.0 million in the first half of 2015 and the per unit share price reduction of $11.22.Contents

~~DPC~~expenditures ~~incurred~~to ~~nominal~~be ~~G&A~~devoted ~~expenses~~primarily ~~during~~to ~~the~~operational ~~first~~improvements, ~~half~~regulatory, health, safety and environmental compliance and progressing other long lead-time projects. However, as a result of the April 2015 offinancing $0transactions which, reduced our near-term cash interest expense, and provided us with flexibility and additional liquidity to advance longer term projects, we decided to proceed with drilling two wells in 2015.~~1 million.~~

~~Interest~~ The ~~Expense. For~~aggregate ~~Venoco,~~levels ~~interest~~of ~~expense~~capital ~~increased~~expenditures ~~$5.0 million~~in ~~(19%)~~2015, toand ~~$31.3 million in~~ the ~~first~~allocation ~~half~~ of ~~2015~~those ~~compared~~expenditures, toare ~~$26.3 million~~dependent inon ~~the~~a ~~first~~variety ~~half~~ of ~~2014.~~factors, ~~The~~including ~~increase~~changes ~~was~~in ~~primarily~~commodity prices, permitting matters, the ~~result~~availability of ~~higher~~capital ~~total~~resources ~~outstanding~~to ~~borrowings. For~~fund ~~DPC,~~the ~~interest~~expenditures ~~expense~~and ~~increased~~changes ~~$7.4 million~~in ~~(17%)~~our tobusiness ~~$50.3 million~~assessments inas ~~the~~to ~~first~~where ~~half~~our ofcapital ~~2015~~can ~~compared~~be tomost ~~$42~~profitably employed.~~9 million~~ inAccordingly, the ~~first~~actual ~~half~~levels of ~~2014.~~capital ~~The~~expenditures ~~incremental~~and ~~difference~~the allocation of ~~$19.0 million~~those expenditures may vary materially from ~~Venoco’s~~our ~~total~~estimates. ~~interest~~Our ~~expense~~other toprincipal ~~DPC’s~~anticipated ~~total~~uses ~~consolidated~~of ~~interest~~cash ~~expense~~are ~~was~~ongoing ~~due~~operating toexpenses and interest payments on ~~DPC’s~~our 12indebtedness.~~25%~~ /Historically, ~~13.00%~~we ~~senior~~have ~~PIK~~used ~~toggle~~funds ~~notes~~from operations and ~~amortization~~borrowings under our revolving credit facility as our primary sources of liquidity. We project that cash flow from operations and cash on hand resulting from the ~~bond~~April ~~discount~~2015 financing transactions will be sufficient to fund our planned capital expenditures and ongoing operations in 2015.

~~Amortization~~ We ofare ~~Deferred~~currently ~~Loan~~pursuing ~~Costs. For~~a ~~Venoco,~~number ~~amortization~~ of ~~deferred~~actions ~~loan~~to ~~costs~~improve ~~increased~~our ~~$0.4 million~~balance ~~(23%) to $2~~sheet.~~1 million~~ inWe ~~the~~cannot ~~first~~assure ~~half~~you ofthat ~~2015~~any ~~compared~~initiatives towill ~~$1.7 million~~be ~~in the first half of 2014~~successful. ~~For~~Uncertainties ~~DPC,~~relating ~~amortization~~to ofour ~~deferred~~capital ~~loan~~resources ~~costs~~and ~~increased~~requirements ~~$0.4~~include ~~million~~the ~~(18%)~~possibility tothat ~~$2.6~~one ~~million~~or inmore ~~the first half~~ of ~~2015~~the ~~compared~~counterparties to ~~$2.2~~our ~~million~~hedging inarrangements ~~the~~may ~~first~~fail ~~half~~to ofperform ~~2014.~~under ~~The~~the ~~increase~~contracts, inthe ~~amortization~~effects of ~~deferred~~changes ~~loan~~in ~~costs~~commodity isprices ~~related~~and todifferentials, ~~the~~and ~~costs associated with~~ the ~~new~~possibility ~~loan~~of ~~agreements~~an ~~which~~unexpected ~~are~~interruption ~~amortized~~in ~~over the estimated lives of the agreements~~production.

~~Loss~~ In ~~(gain)~~addition, Venoco is subject to various legal and contractual limitations on ~~Extinguishment~~its ofability ~~Debt~~to pay dividends or otherwise make distributions to DPC, and DPC will be 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. ~~recognized~~Venoco’s aagreements ~~$67~~permit it to pay dividends to DPC in certain circumstances.5 ~~million~~We ~~gain~~do not expect these criteria to be met in 2015. The February and August 2015 interest payments on ~~extinguishment~~DPC’s ofnotes ~~debt~~were asmade a100% ~~result~~in ofkind, ~~the~~and ~~debt~~we ~~exchange~~expect ~~that~~to ~~occurred~~continue making interest payments 100% in ~~April~~kind ~~2015~~for the foreseeable future.

~~Commodity~~ Because ~~Derivative~~we ~~Losses~~must ~~(Gains),~~dedicate ~~Net. The~~a ~~following~~substantial ~~table~~portion ~~sets~~of ~~forth~~our cash flow from operations to the ~~components~~payment of ~~commodity~~amounts ~~derivative~~due ~~losses~~under ~~(gains)~~our debt agreements, ~~net~~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 ~~condensed~~debt ~~consolidated~~agreements ~~statements~~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, ~~for~~seek to restructure our indebtedness, and/or seek additional capital. Needed capital may not be available on acceptable terms or at all. Our ability to raise funds through the ~~periods~~incurrence ~~indicated~~of (additional indebtedness and certain other means is limited by covenants in ~~thousands):~~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.

	Six Months Ended June 30,
	2014		2015
Realized commodity derivative losses (gains)	$	8,055	$	(40,262	)
Unrealized commodity derivative losses (gains) for changes in fair value	8,760		37,062
Commodity derivative losses (gains), net	$	16,815	$	(3,200	)

The additional indebtedness we incurred in connection with and after the going private transaction, significant decreases in the price of oil and various operational issues have increased the debt- and liquidity-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 further adverse changes in commodity prices, and other unfavorable economic conditions. Prior to the termination of Venoco’s revolving credit facility, we were required to obtain numerous amendments to and waivers from the lenders under the facility as a result of anticipated or actual breaches of the covenants in the facility. We may be forced to seek similar amendments or waivers from current or future lenders, and there is no assurance that we will be able to obtain them in a timely manner or at all. We are currently exploring additional deleveraging efforts and have significantly curtailed our planned capital expenditures for 2015 relative to prior years. There can be no assurance that our deleveraging efforts will be successful.

Realized commodity derivative gains or losses represent the difference between the strike prices in the contracts settled during the period and the ultimate settlement prices. The realized commodity derivative gains in the first half of 2015 reflect the settlement of contracts at prices below the relevant strike prices. Additionally, in the first half of 2015, $15.6 million of the realized gain was related to the settlement of our 2016 derivative contract with ABN AMRO. 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. 34

~~Income~~ Table ~~Tax~~of Expense (Benefit). Due to our valuation allowance, there was no income tax expense (benefit) recorded for the six month periods ended June 30, 2015 or 2014. 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.Contents

31Off-Balance Sheet Arrangements

~~Table~~ At September 30, 2015, we had no existing off-balance sheet arrangements, as defined under SEC rules, that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of ~~Contents~~operations, liquidity, capital expenditures or capital resources.

~~Net~~ Adjusted ~~Income~~Consolidated ~~(Loss). For~~Net ~~Venoco,~~Tangible net loss for the first half of 2015 was $131.6 million compared to the net income of $0.8 million for the same period in 2014. For DPC, net loss for the first half of 2015 was $151.2 million compared to the net loss of $16.6 million for the same period in 2014. The changes between periods are the result of the items discussed above.Assets

~~Liquidity~~ As ~~and~~of ~~Capital~~September 30, ~~Resources~~2015, 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 $847 million.

~~Venoco’s~~ ITEM ~~primary sources of liquidity are cash generated from our operations and proceeds from debt transactions~~3. Quantitative In addition, Venoco has commodity derivative positions with a net asset value of $39.2 million as of June 30, 2015. If unwound, these positions could provide an additional source of liquidity subject to the commodity price environment at the relevant time. Venoco unwound one position on April 2, 2015, which hedged 1,715 barrels per day of our 2016 oil production, receiving proceeds of $15.6 million. DPC’s primary sources of liquidity are distributions from Venoco and ~~the~~Qualitative ~~issuance~~Disclosures ofAbout ~~debt~~Market ~~securities.~~Risk

~~Cash~~ This ~~Flows~~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 in cash flows resulting from changes in commodity prices. 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 cash flows than we would have if we were unhedged in times of higher oil and natural gas prices, management believes that reducing volatility associated with commodity prices 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.

	Venoco, Inc.						Denver Parent Corporation
	Six Months Ended June 30,						Six Months Ended June 30,
	2014			2015			2014			2015
	(in thousands)
Cash (used in) provided by operating activities	$	30,857		$	11,192		$	15,209		$	11,123
Cash (used in) provided by investing activities	(52,357		)	(5,616		)	(52,357		)	(5,616		)
Cash (used in) provided by financing activities	20,737			92,978			24,533			92,978

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

~~Net~~ Commodity ~~cash~~Derivative provided by operating activities for Venoco was $11.2 million in the first half of 2015 compared to net cash provided by operating activities of $30.9 million in the 2014 period. Cash flows provided by operating activities in the first half of 2015 as compared to cash flows provided by operating activities in the first half of 2014 were impacted by the lower oil prices, lower oil and natural gas production, and the effect of shutting in Platform Holly due to the pipeline spill.Transactions

~~Net~~ Commodity ~~cash~~Derivative ~~provided~~Agreements. As byof ~~operating~~September 30, ~~activities~~2015, ~~for~~we ~~DPC~~had ~~was~~entered ~~$11~~into various swap and collar agreements related to our oil production.~~1 million~~ inThe ~~the~~aggregate ~~first~~economic ~~half~~effects of ~~2015~~those ~~compared~~agreements toare ~~$15~~summarized below.~~2 million~~ ~~provided~~Location and quality differentials attributable to our properties are not included in the ~~2014~~following ~~period~~prices. The ~~difference~~agreements inprovide for monthly settlement based on the ~~amounts~~differential between ~~Venoco~~the agreement price and ~~DPC~~the ~~relates~~price toper ~~additional~~the ~~DPC~~applicable ~~interest~~index, Inter-Continental ~~expense~~Exchange Brent (“Brent”) (oil).

Net cash used in investing activities for Venoco and DPC was $5.6 million in the first half of 2015 compared to net cash used by investing activities of $52.4 million in the 2014 period. The primary investing activities in the first half of 2015 were $7.3 million in capital expenditures on oil properties related to our capital expenditure program, partially offset by $1.8 million received from the final settlement from the sale of Montalvo and certain other assets. The primary investing activities in the first half of 2014 were $52.0 million in capital expenditures on oil properties related to our capital expenditure program.


	Oil (BRENT)
		Weighted Avg.
	Barrels/day	Prices per Bbl
January 1 - December 31, 2015
Swaps	460	$ 100.40
Collars	4,135	$90.00/$100.00
January 1 - December 31, 2016
Swaps	1,715	$ 96.00

Net cash provided by financing activities for Venoco was $92.9 million in the first half of 2015 compared to net cash provided by financing activities of $20.7 million during the 2014 period. The primary financing activities in the first half of 2015 were borrowings of $340 million and payments of $155 million. The primary financing activities in the first half of 2014 were borrowings of $132.0 million payments of $107 million and a dividend paid to DPC of $3.9 million. 35

~~Net~~ Table ~~cash provided by financing activities for DPC was $92.9 million in the first half~~ of ~~2015 compared to net cash provided by financing activities of $24.5 million during the 2014 period.~~Contents

~~Capital~~Portfolio ~~Resources~~of ~~and~~Derivative ~~Requirements~~Transactions

Our ~~current~~portfolio ~~2015 capital expenditure budget is $33 million. This amount is substantially less than it has been in past years and is reflective~~ of ~~current~~commodity ~~market~~derivative ~~and~~transactions economic conditions. We previously expected our 2015 capital expenditures to be devoted primarily to operational improvements, regulatory, health, safety and environmental compliance and progressing other long lead-time projects. However, as ~~a result~~ of ~~the recently completed series of financing transactions which reduced our near-term cash interest expense~~September 30, ~~and provided us with flexibility and additional liquidity to advance longer term projects, we have decided to proceed with drilling activities in~~ 2015~~. We~~ ~~are~~is ~~currently~~summarized drilling one well off of Platform Gail at the Sockeye field into the M2 zone. Additionally we are preparing an engineering program for the drilling of one additional well into the M2 zone at Platform Gail.below:

The aggregate levels of capital expenditures in 2015, and the allocation of those expenditures, are dependent on a variety of factors, including changes in commodity prices, permitting matters, 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 Oil


			Quantity	Strike Price
Type of Contract	Counterparty	Basis	(Bbl/d)	($/Bbl)	Term
Collar	Bank of America	Brent	1,000	$90.00/$98.00	Jan 1, 14 - Dec 31, 15
Collar	Bank of America	Brent	1,000	$90.00/$101.25	Jan 1, 14 - Dec 31, 15
Collar	Bank of America	Brent	1,675	$90.00/$98.15	Jan 1, 14 - Dec 31, 15
Collar	Bank of America	Brent	460	$90.00/$108.40	Jan 1, 14 - Dec 31, 15
Swap	Bank of America	Brent	460	$ 100.40	Jan 1, 15 - Dec 31, 15
Swap	Bank of America	Brent	1,715	$ 96.00	Jan 1, 16 - Dec 31, 16

~~Table~~ In April 2015, Venoco unwound one position, which hedged 1,715 barrels per day of ~~Contents~~our 2016 oil production receiving proceeds of $15.6 million.

~~expenditures~~ We enter into derivative contracts, primarily collars, swaps and option contracts, in an effort to mitigate the ~~allocation~~risk of ~~those~~market ~~expenditures~~price ~~may~~fluctuations. ~~vary~~The ~~materially~~objective ~~from~~of our ~~estimates~~hedging activities and the use of derivative financial instruments is to achieve more predictable cash flows. Our ~~other~~hedging ~~principal~~activities ~~anticipated~~seek ~~uses~~to ofmitigate ~~cash~~our ~~are~~exposure ~~ongoing~~to ~~operating~~price ~~expenses~~declines and ~~interest~~allow ~~payments~~us onmore flexibility to continue to execute our ~~indebtedness.~~capital ~~Historically,~~expenditure weplan ~~have~~even ~~used~~if ~~funds~~market ~~from~~prices ~~operations~~decline. Our collar and ~~borrowings~~swap ~~under~~contracts, ~~our~~however, ~~revolving~~prevent ~~credit~~us ~~facility~~from asreceiving ~~our~~the ~~primary~~full ~~sources~~advantage of ~~liquidity~~increases in oil prices above the maximum fixed amount specified in the hedge agreement. We ~~project~~do ~~that~~not ~~cash~~enter ~~flow~~into ~~from~~hedge ~~operations~~positions for amounts greater than our expected production levels; however, if actual production is less than the amount we have hedged and ~~cash~~the onprice ~~hand~~of ~~resulting~~oil ~~from~~or ~~our~~natural ~~recent~~gas ~~financing~~exceeds ~~transactions~~a fixed price in a hedge contract, we will be ~~sufficient~~required to ~~fund~~make ~~our~~payments ~~planned~~against ~~capital~~which ~~expenditures~~there are no offsetting sales of production. This could impact our liquidity and ~~ongoing~~our ~~operations~~ability into ~~2015~~fund future capital expenditures.

We In ~~are~~addition, ~~currently~~the ~~pursuing~~use aof ~~number~~derivatives ofinvolves ~~actions~~the torisk ~~improve~~that ~~our~~the ~~balance~~counterparties ~~sheet.~~to Wesuch ~~cannot~~instruments ~~assure~~will ~~you~~be ~~that~~unable ~~any~~to ~~initiatives~~meet ~~will~~the befinancial ~~successful.~~terms ~~Uncertainties~~of ~~relating~~such tocontracts. ~~our~~We ~~capital~~generally ~~resources~~have ~~and~~netting ~~requirements~~arrangements ~~include~~with ~~the~~our ~~possibility~~counterparties that ~~one~~provide orfor ~~more~~the offset of ~~the~~payables ~~counterparties~~against toreceivables ~~our~~from ~~hedging~~separate derivative arrangements ~~may~~with ~~fail~~that tocounterparty ~~perform~~in ~~under~~ the ~~contracts,~~event ~~the~~of ~~effects~~contract oftermination. ~~changes~~The inderivative ~~commodity~~contracts ~~prices~~may ~~and~~be ~~differentials,~~terminated ~~and~~by a non-defaulting party in the ~~possibility~~event of andefault ~~unexpected~~by ~~interruption~~one inof ~~production~~the parties to the agreement.

In We ~~addition,~~have ~~Venoco~~elected isnot ~~subject~~ to ~~various~~apply ~~legal~~cash ~~and~~flow ~~contractual~~hedge ~~limitations~~accounting ~~on its ability~~ to ~~pay~~any ~~dividends~~of orour ~~otherwise~~derivative ~~make~~transactions ~~distributions to DPC,~~ and ~~DPC~~we ~~will~~therefore berecognize ~~able~~ mark-to-market ~~pay~~gains ~~interest~~and onlosses ~~its 12.25% /13.00% senior PIK toggle notes~~ in ~~cash~~earnings ~~only~~currently, ifrather itthan ~~receives~~deferring ~~cash~~such ~~dividends~~amounts ~~or distributions from Venoco. Venoco’s agreements permit it to pay dividends to DPC~~ in ~~certain~~accumulated ~~circumstances.~~other Wecomprehensive doincome ~~not~~for ~~expect~~those ~~these~~commodity ~~criteria~~derivatives tothat bewould ~~met~~qualify inas ~~2015.~~cash ~~The~~flow ~~February 2015 interest payment on DPC’s notes was made 100% in kind, and we expect to continue making interest payments 100% in kind for the foreseeable future~~hedges.

~~Because~~ All wederivative ~~must~~instruments ~~dedicate~~are arecorded ~~substantial~~on ~~portion of our cash flow from operations to~~ the ~~payment~~balance ofsheet ~~amounts~~at ~~due~~fair ~~under~~value. ~~our~~Fair ~~debt~~value ~~agreements, that portion of our cash flow~~ is ~~not~~generally ~~available~~determined ~~for~~based ~~other purposes. Our ability to make scheduled interest payments~~ on ~~our~~the ~~indebtedness,~~difference ~~maintain~~between ~~compliance with~~ the ~~covenants~~fixed incontract ~~our~~price ~~debt agreements~~ and ~~pursue~~the ~~our~~underlying ~~capital~~market ~~expenditure~~price ~~plan~~at ~~will~~the ~~depend~~determination todate. aChanges ~~significant~~in ~~extent~~the onfair ~~our~~value ~~financial and operating performance, which is subject to prevailing economic conditions, commodity prices and a variety~~ of ~~other~~derivatives ~~factors. If our cash flow and other capital resources~~ are ~~insufficient~~recorded toin ~~fund~~commodity ~~our~~derivative ~~debt~~(gains) ~~service~~losses ~~obligations~~on ~~and~~the ~~our~~consolidated ~~capital~~statement ~~expenditure~~of ~~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~~, seek to restructure our indebtedness, and/or seek additional capital~~. ~~Needed~~As ~~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~~September 30, ~~pursuant to mandatory prepayment provisions in our debt agreements~~2015, ~~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~~fair ~~that~~value ~~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~~commodity ~~obligations~~derivatives orwas ~~finance~~a ~~the~~net ~~capital~~asset ~~expenditures~~of ~~necessary to replace our reserves~~$43.8 million.

~~The~~ Interest ~~additional~~Rate indebtedness we incurred in connection with and after the going private transaction, significant decreases in the price of oil and various operational issues have increased the debt- and liquidity-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 further adverse changes in commodity prices and other unfavorable economic conditions. Prior to the termination of Venoco’s revolving credit facility, we were required to obtain numerous amendments to and waivers from the lenders under the facility as a result of anticipated or actual breaches of the covenants in the facility. We may be forced to seek similar amendments or waivers from current or future lenders, and there is no assurance that we will be able to obtain them in a timely manner or at all. We are currently exploring additional deleveraging efforts and have significantly curtailed our planned capital expenditures for 2015 relative to prior years. There can be no assurance that our deleveraging efforts will be successful.Risk

~~Off-Balance~~ We ~~Sheet~~are ~~Arrangements~~subject to interest rate risk with respect to amounts borrowed under the term Loan facility because those amounts bear interest at a variable rate. The interest rates associated with our secured and senior notes are fixed for the term of the notes.

At See ~~June 30,~~notes ~~2015,~~to weour ~~had~~consolidated nofinancial ~~existing~~statements ~~off-balance~~for ~~sheet arrangements, as defined under SEC rules, that have or are reasonably likely to have~~ a ~~material~~discussion ~~current~~of ~~or future effect on~~ our ~~financial~~long-term ~~condition,~~debt ~~revenues~~as ~~or expenses, results~~ of ~~operations~~September 30, ~~liquidity, capital expenditures or capital resources~~2015.

~~Adjusted Consolidated Net Tangible Assets~~ 36

As Table of ~~June 30, 2015, 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 $880 million.~~Contents

33ITEM 4. Controls and Procedures

~~Table~~ Disclosure ofControls ~~Contents~~and Procedures

~~ITEM~~ Our 3.management, ~~Quantitative~~with the participation of Venoco’s and ~~Qualitative~~DPC’s ~~Disclosures~~principal ~~About~~executive ~~Market~~officer ~~Risk~~and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2015. Based on the evaluation, those officers believe that:

~~This~~· ~~section~~our ~~provides~~disclosure ~~information~~controls ~~about~~and ~~derivative~~procedures ~~financial~~(including ~~instruments~~those ~~we use to manage commodity price volatility. Due to the historical volatility~~ of ~~crude~~both ~~oil~~Venoco and ~~natural~~DPC) ~~gas~~were ~~prices,~~effective weto ~~have~~ensure ~~implemented~~that ainformation ~~hedging~~required strategy aimed at reducing the variability in cash flows resulting from changes in commodity prices. Currently, we purchase puts and enter into other derivative transactions such as collars and fixed price swaps in order to ~~hedge~~be ~~our~~disclosed ~~exposure~~by tous ~~changes~~ in ~~commodity prices. All contracts are settled with cash and do not require~~ the ~~delivery~~reports ~~of a physical quantity to satisfy settlement. While this hedging strategy may result in us having lower cash flows than~~ we ~~would~~file ~~have~~or ifsubmit weunder ~~were~~the ~~unhedged~~Securities inExchange ~~times~~Act of ~~higher~~1934 ~~oil and natural gas prices, management believes that reducing volatility associated with commodity prices~~ is ~~beneficial. We may~~recorded, ~~from time to time~~processed, ~~opportunistically~~summarized ~~restructure~~and ~~existing~~reported ~~derivative~~within ~~contracts or enter into new transactions to effectively modify~~ the ~~terms~~time ofperiods ~~current~~specified ~~contracts~~ in ~~order to improve~~ the ~~pricing~~SEC’s ~~parameters~~rules inand ~~existing~~forms; 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.and

~~This~~· ~~section~~our ~~also~~disclosure ~~provides~~controls and procedures were effective to ensure that information ~~about~~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 ~~interest~~management, ~~rate~~including ~~risk.~~our ~~See~~principal ~~“—Interest~~executive ~~Rate~~and ~~Risk~~principal financial officers, as appropriate to allow timely decisions regarding required disclosure.”

~~Commodity~~ Internal ~~Derivative~~Control ~~Transactions~~Over Financial Reporting

~~Commodity~~ On ~~Derivative Agreements. As of June~~August 301, 2015, weJoel ~~had~~Reed ~~entered~~and ~~into~~Rick ~~various swap~~Walker, ~~collar~~both ~~and~~members ~~option~~of ~~agreements~~Venoco’s ~~related~~Audit toCommittee, ~~our~~resigned ~~oil~~their ~~and~~positions ~~natural~~with ~~gas~~the ~~production.~~committee ~~The~~and ~~aggregate~~the ~~economic effects of those agreements are summarized below~~board. Consequently, ~~Location~~the ~~and~~Company ~~quality~~no ~~differentials~~longer ~~attributable~~has toany ~~our~~independent ~~properties~~directors. We are ~~not~~currently ~~included~~evaluating in the ~~following~~effects ~~prices.~~of ~~The~~their ~~agreements~~departure ~~provide for monthly settlement based~~ on ~~the~~our ~~differential~~internal ~~between~~controls ~~the~~over ~~agreement~~financial ~~price and the price per the applicable index, Inter-Continental Exchange Brent (“Brent”) (oil)~~reporting.

	Oil (Brent)
	Barrels/day	Weighted Avg. Prices per Bbl
January 1 - December 31, 2015:
Swaps	460	$100.40
Collars	4,135	$90.00/$100.00
January 1 - December 31, 2016:
Swap	1,715	$96.00

~~Portfolio~~ Table of ~~Derivative Transactions~~Contents

~~Our portfolio of commodity derivative transactions as of June~~ PART ~~30,~~II—OTHER ~~2015 is summarized below:~~INFORMATION

~~Oil~~ Item 1. LEGAL PROCEEDINGS

Type of Contract	Counterparty	Basis	Quantity (Bbl/d)	Strike Price ($/Bbl)	Term
Collar	Bank of America	Brent	1,000	$90.00/$98.00	Jan 1, 14 - Dec 31, 15
Collar	Bank of America	Brent	1,000	$90.00/$101.25	Jan 1, 14 - Dec 31, 15
Collar	Bank of America	Brent	1,675	$90.00/$98.15	Jan 1, 14 - Dec 31, 15
Collar	Bank of America	Brent	460	$90.00/$108.40	Jan 1, 15 - Dec 31, 15
Swap	Bank of America	Brent	460	$100.40	Jan 1, 15 - Dec 31, 15
Swap	Bank of America	Brent	1,715	$96.00	Jan 1, 16 - Dec 31, 16

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

~~In April~~ Item ~~2015, Venoco unwound one position, which hedged 1,715 barrels per day of our 2016 oil production receiving proceeds of $15~~1A.~~6 million.~~ RISK FACTORS

34 In addition to the other information set forth in this report, you should carefully consider the factors discussed in “Risk Factors” in the Venoco / DPC Annual Report on Form 10-K for the year ended December 31, 2014, which could materially affect our business, financial condition and/or future results. The risks described in this report and in the 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.

~~Table~~ Item 2. UNREGISTERED ofSALES ~~Contents~~OF EQUITY SECURITIES AND USE OF PROCEEDS

We Not enter into derivative contracts, primarily collars, swaps and option contracts, in an effort 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.Applicable

~~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~~ Item 3. DEFAULTS WeUPON ~~generally~~SENIOR 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.SECURITIES

We Not have elected not to apply cash flow 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.Applicable

~~All derivative instruments are recorded on the balance sheet at fair value~~ Item 4. MINE ~~Fair~~SAFETY 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, 2015, the fair value of our commodity derivatives was a net asset of $39.2 million.DISCLOSURES

~~Interest~~ Not ~~Rate Risk~~Applicable

~~We are subject to interest rate risk with respect to amounts borrowed under the Term Loan facility because those amounts bear interest at a variable rate~~ Item 5. OTHER ~~The interest rates associated with our secured and senior notes are fixed for the term of the notes.~~INFORMATION

~~See~~ Not ~~notes to our consolidated financial statements for a discussion of our long-term debt as of June 30, 2015.~~Applicable

~~ITEM 4. Controls and Procedures~~ 38

~~Disclosure~~ Table ~~Controls~~of ~~and Procedures~~Contents

Our management, with the participation of Venoco’s and DPC’s principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of JuneItem ~~30, 2015~~6. ~~Based on the evaluation, those officers believe that:~~ EXHIBITS

· our disclosure controls and procedures (including those of both Venoco and DPC) 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

Exhibit Number		Exhibit
3.1		Amended and Restated Certificate of Incorporation of Venoco, Inc.

31.1		Certification of the Chief Executive Officer of Venoco, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of the Chief Financial Officer of Venoco, Inc. Pursuant to Section 302 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.

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.

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, 2015, 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.

· 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 principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. 39

~~Internal~~ Table ~~Control~~of ~~Over Financial Reporting~~Contents

On August 1, 2015 Joel Reed and Rick Walker, both members of the Audit Committee, resigned their positions with the committee and the board. Consequently, the Company no longer has any independent directors. We are currently evaluating the effects of their departure on our internal controls over financial reporting.SIGNATURES

35 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.

~~Table~~ November 12, ~~of Contents~~2015

~~PART II—OTHER~~VENOCO, ~~INFORMATION~~INC. By: /s/ MARK A. DEPUY Name: Mark A. DePuy Title: Chief Executive Officer By: /s/ SCOTT M. PINSONNAULT Name: Scott M. Pinsonnault Title: Chief Financial Officer

~~Item~~ Pursuant 1.to ~~LEGAL~~the ~~PROCEEDINGS~~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.

~~The~~ November 12, ~~information set forth in the financial statements included in this report is incorporated by reference herein.~~2015

~~Item~~DENVER 1APARENT CORPORATION By: /s/ TIMOTHY M. ~~RISK~~MARQUEZ ~~FACTORS~~Name: Timothy M. Marquez Title: Chief Executive Officer By: /s/ SCOTT M. PINSONNAULT Name: Scott M. Pinsonnault Title: Chief Financial Officer

In addition to the other information set forth in this report, you should carefully consider the factors discussed in “Risk Factors” in the Venoco / DPC Annual Report on Form 10-K for the year ended December 31, 2014, which could materially affect our business, financial condition and/or future results. The risks described in this report and in the 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. 40

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
10.1		Employment Agreement, dated May 1, 2015, by and between Venoco, Inc. and Scott M. Pinsonnault.
31.1		Certification of the Chief Executive Officer of Venoco, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of the Chief Financial Officer of Venoco, Inc. Pursuant to Section 302 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.
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.
101		The following financial information from the quarterly report on Form 10-Q of Venoco, Inc. and Denver Parent Corporation for the quarter ended June 30, 2015, 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.

Table of Contents

SIGNATURES

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

August 19, 2015

VENOCO, INC. By: /s/ MARK A. DEPUY Name: Mark A. DePuy Title: Chief Executive Officer By: /s/ SCOTT M. PINSONNAULT Name: Scott M. Pinsonnault Title: Chief Financial Officer

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 19, 2015

DENVER PARENT CORPORATION By: /s/ TIMOTHY M. MARQUEZ Name: Timothy M. Marquez Title: Chief Executive Officer By: /s/ SCOTT M. PINSONNAULT Name: Scott M. Pinsonnault Title: Chief Financial Officer

Filing Compare · DENVER PARENT Corp