Denver Parent 10-K 6 Jun 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	May. 13, 2016
Document and Entity Information
Entity Registrant Name	Denver Parent Corporation
Entity Central Index Key	1,588,242
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	Yes
Entity Current Reporting Status	No
Entity Filer Category	Non-accelerated Filer
Entity Public Float	$ 0
Entity Common Stock, Shares Outstanding		30,297,459
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 90,297	$ 15,656
Restricted funds	79,589
Accounts receivable	10,610	14,912
Insurance receivable	16,500
Inventories	1,452	3,370
Other current assets	3,859	4,721
Commodity derivatives	33,688	48,298
Total current assets	235,995	86,957
Oil and gas properties, full cost method of accounting
Proved	1,903,172	1,866,415
Unproved		8,360
Accumulated depletion	(1,860,217)	(1,400,738)
Net oil and gas properties	42,955	474,037
Other property and equipment, net of accumulated depreciation and amortization of $14,566 and $14,687 at December 31, 2014 and December 31, 2015, respectively	13,036	14,477
Net property, plant and equipment	55,991	488,514
OTHER ASSETS:
Commodity derivatives		29,793
Other	3,422	4,069
Total other assets	3,422	33,862
TOTAL ASSETS	295,408	609,333
CURRENT LIABILITIES:
Current portion of long-term debt	998,027
Accounts payable and accrued liabilities	37,916	20,535
Interest payable	20,912	17,329
Share-based compensation	2	2,236
Total current liabilities	1,056,857	40,100
LONG-TERM DEBT	0	828,451
ASSET RETIREMENT OBLIGATIONS	33,276	30,351
SHARE-BASED COMPENSATION	3	648
Total liabilities	$ 1,090,136	$ 899,550
COMMITMENTS AND CONTINGENCIES (note 7)
STOCKHOLDERS' EQUITY (DEFICIT):
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 December 31, 2015; 30,297,459 DPC shares issued and outstanding at December 31, 2014 and December 31, 2015)	$ 303	$ 303
Additional paid-in capital	74,400	73,902
Retained earnings (accumulated deficit)	(869,431)	(364,422)
TOTAL STOCKHOLDERS’ EQUITY (DEFICIT)	(794,728)	(290,217)
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	295,408	609,333
Venoco, Inc.
CURRENT ASSETS:
Cash and cash equivalents	90,165	15,455
Restricted funds	79,589
Accounts receivable	10,610	14,912
Insurance receivable	16,500
Inventories	1,452	3,370
Other current assets	3,859	4,715
Commodity derivatives	33,688	48,298
Total current assets	235,863	86,750
Oil and gas properties, full cost method of accounting
Proved	1,903,172	1,866,415
Unproved		8,360
Accumulated depletion	(1,860,217)	(1,400,738)
Net oil and gas properties	42,955	474,037
Other property and equipment, net of accumulated depreciation and amortization of $14,566 and $14,687 at December 31, 2014 and December 31, 2015, respectively	13,036	14,477
Net property, plant and equipment	55,991	488,514
OTHER ASSETS:
Commodity derivatives		29,793
Other	3,422	4,069
Total other assets	3,422	33,862
TOTAL ASSETS	295,276	609,126
CURRENT LIABILITIES:
Current portion of long-term debt	686,877
Accounts payable and accrued liabilities	37,916	20,535
Interest payable	20,912	17,329
Share-based compensation	2	2,236
Total current liabilities	745,707	40,100
LONG-TERM DEBT	0	557,872
ASSET RETIREMENT OBLIGATIONS	33,276	30,351
SHARE-BASED COMPENSATION	3	648
Total liabilities	$ 778,986	$ 628,971
COMMITMENTS AND CONTINGENCIES (note 7)
STOCKHOLDERS' EQUITY (DEFICIT):
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 December 31, 2015; 30,297,459 DPC shares issued and outstanding at December 31, 2014 and December 31, 2015)	$ 299	$ 299
Additional paid-in capital	285,618	285,120
Retained earnings (accumulated deficit)	(769,627)	(305,264)
TOTAL STOCKHOLDERS’ EQUITY (DEFICIT)	(483,710)	(19,845)
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	$ 295,276	$ 609,126

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Other property and equipment, accumulated depreciation and amortization (in dollars)	$ 14,687	$ 14,566
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	30,297,459	30,297,459
Common stock, shares outstanding	30,297,459	30,297,459
Venoco, Inc.
Other property and equipment, accumulated depreciation and amortization (in dollars)	$ 14,687	$ 14,566
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	29,936,378	29,936,378
Common stock, shares outstanding	29,936,378	29,936,378

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REVENUES:
Oil and natural gas sales									$ 58,485	$ 222,052	$ 313,373
Other									2,235	2,157	4,129
Total revenues	$ 9,278	$ 11,154	$ 19,870	$ 20,418	$ 36,322	$ 57,851	$ 67,039	$ 62,997	60,720	224,209	317,502
EXPENSES:
Lease operating expense									54,367	72,337	77,786
Production and property taxes									4,653	7,611	3,521
Transportation expense									201	201	181
Depletion, depreciation and amortization									23,599	44,064	48,840
Ceiling test and other impairments									439,858	817
Accretion of asset retirement obligations									2,150	2,491	2,477
General and administrative, net of amounts capitalized									29,066	20,352	50,664
Total expenses									553,894	147,873	183,469
Income (loss) from operations	(119,123)	(205,077)	(156,225)	(12,749)	7,406	23,660	24,293	20,977	(493,174)	76,336	134,033
FINANCING COSTS AND OTHER:
Interest expense, net									108,278	87,025	86,640
Amortization of deferred loan costs									5,180	4,289	4,754
Loss (gain) on extinguishment of debt									(67,515)	2,347	58,472
Commodity derivative losses (gains), net									(34,108)	(101,899)	12,607
Total financing costs and other									11,835	(8,238)	162,473
Income (loss) before income taxes									(505,009)	84,574	(28,440)
Net income (loss)	(139,674)	(214,179)	(129,759)	(21,397)	70,963	30,231	(17,493)	872	(505,009)	84,574	(28,440)
Venoco, Inc.
REVENUES:
Oil and natural gas sales									58,485	222,052	313,373
Other									2,235	2,157	4,129
Total revenues	9,278	11,154	19,870	20,418	36,322	57,851	67,039	62,997	60,720	224,209	317,502
EXPENSES:
Lease operating expense									54,367	72,337	77,786
Production and property taxes									4,653	7,611	3,521
Transportation expense									201	201	181
Depletion, depreciation and amortization									23,599	44,064	48,840
Ceiling test and other impairments									439,858	817
Accretion of asset retirement obligations									2,150	2,491	2,477
General and administrative, net of amounts capitalized									28,996	19,926	50,403
Total expenses									553,824	147,447	183,208
Income (loss) from operations	(119,122)	(205,077)	(156,224)	(12,681)	7,442	23,711	24,378	21,231	(493,104)	76,762	134,294
FINANCING COSTS AND OTHER:
Interest expense, net									69,187	52,609	65,114
Amortization of deferred loan costs									3,695	3,268	3,705
Loss (gain) on extinguishment of debt									(67,515)	2,347	38,549
Commodity derivative losses (gains), net									(34,108)	(101,899)	12,607
Total financing costs and other									(28,741)	(43,675)	119,975
Income (loss) before income taxes									(464,363)	120,437	14,319
Net income (loss)	$ (129,427)	$ (203,322)	$ (119,820)	$ (11,794)	$ 80,105	$ 39,525	$ (8,746)	$ 9,553	$ (464,363)	$ 120,437	$ 14,319

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Common StockVenoco, Inc.	Common Stock	Additional Paid-in CapitalVenoco, Inc.	Additional Paid-in Capital	Retained Earnings (Accumulated Deficit)Venoco, Inc.	Retained Earnings (Accumulated Deficit)	Venoco, Inc.	Total
BALANCE at Dec. 31, 2012	$ 299	$ 299	$ 124,358	$ 68,421	$ (420,315)	$ (420,556)	$ (295,658)	$ (351,836)
BALANCE (in shares) at Dec. 31, 2012	29,936,000	29,936,000
Increase (Decrease) in Stockholders' Equity
Going private transaction share repurchase costs			(9)	(9)			(9)	(9)
Excess of share-based compensation expense recognized over payments made			754	754			754	754
DPC capital contribution to Venoco			158,385	3,108			158,385	3,108
Dividend paid to DPC					(15,800)		(15,800)
Issuance of ESOP		$ 2		(2)
Issuance of ESOP (in shares)		215,000
Net income (loss)					14,319	(28,440)	14,319	(28,440)
BALANCE at Dec. 31, 2013	$ 299	$ 301	283,488	72,272	(421,796)	(448,996)	(138,009)	$ (376,423)
BALANCE (in shares) at Dec. 31, 2013	29,936,000	30,151,000
Increase (Decrease) in Stockholders' Equity
Issuance of common stock pursuant to Employee Stock Purchase Plan (in shares)								146,525
Excess of share-based compensation expense recognized over payments made			1,632	1,632			1,632	$ 1,632
Dividend paid to DPC					(3,905)		(3,905)
Issuance of ESOP		$ 2		(2)
Issuance of ESOP (in shares)		146,000
Net income (loss)					120,437	84,574	120,437	84,574
BALANCE at Dec. 31, 2014	$ 299	$ 303	285,120	73,902	(305,264)	(364,422)	$ (19,845)	$ (290,217)
BALANCE (in shares) at Dec. 31, 2014	29,936,000	30,297,000					29,936,378	30,297,459
Increase (Decrease) in Stockholders' Equity
Excess of share-based compensation expense recognized over payments made			498	498			$ 498	$ 498
Net income (loss)					(464,363)	(505,009)	(464,363)	(505,009)
BALANCE at Dec. 31, 2015	$ 299	$ 303	$ 285,618	$ 74,400	$ (769,627)	$ (869,431)	$ (483,710)	$ (794,728)
BALANCE (in shares) at Dec. 31, 2015	29,936,000	30,297,000					29,936,378	30,297,459

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (505,009)	$ 84,574	$ (28,440)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	23,599	44,064	48,840
Ceiling test and other impairments	439,858	817
Accretion of asset retirement obligations	2,150	2,491	2,477
Share-based compensation	498	1,632	754
Interest paid-in-kind	51,394	25,468	5,005
Amortization of deferred loan costs	5,180	4,289	4,754
Loss (gain) on extinguishment of debt	(67,515)	2,347	58,472
Amortization of bond discounts and other	5,762	1,096	1,074
Unrealized commodity derivative (gains) losses and amortization of premiums	44,403	(101,816)	(15,521)
Changes in operating assets and liabilities:
Accounts receivable	4,302	8,868	11,759
Insurance receivable	(16,500)
Inventories	418	1,796	(65)
Other current assets	818	(262)	(328)
Other assets	(197)	1,758	(1,793)
Accounts payable and accrued liabilities	23,146	(11,363)	(17,238)
Share-based compensation liabilities	(2,879)	(34,560)	16,579
Net premiums paid on derivative contracts			(1,495)
Net cash provided by operating activities	9,428	31,199	84,834
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties	(29,405)	(87,660)	(101,995)
Acquisitions of oil and natural gas properties	(21)	(38)	(45)
Expenditures for other property and equipment	(193)	(647)	(2,490)
Proceeds provided by sale of oil and natural gas properties	1,844	196,534	101,077
Net cash (used in) investing activities	(27,775)	108,189	(3,453)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	340,000	182,000	705,025
Principal payments on long-term debt	(155,000)	(322,000)	(781,905)
Payments for deferred loan costs		(1,068)	(7,491)
Debt issuance costs	(12,423)
Increase in restricted cash	(79,589)
Premium for early retirement of debt			(37,091)
Going private share repurchase costs			(9)
Denver Parent Corporation capital contribution			3,108
Net cash provided by (used in) financing activities	92,988	(141,068)	(118,363)
Net (decrease) increase in cash and cash equivalents	74,641	(1,680)	(36,982)
Cash and cash equivalents, beginning of period	15,656	17,336	54,318
Cash and cash equivalents, end of period	90,297	15,656	17,336
Supplemental Disclosure of Cash Flow Information-
Cash paid for interest	45,109	72,263	79,300
Supplemental Disclosure of Noncash Activities-
(Decrease) increase in accrued capital expenditures	(785)	(11,223)	(5,789)
Write off of deferred loan costs	3,396	2,347	10,763
Excess of share-based compensation expense recognized over payments made	498	1,632	754
Denver Parent Corporation
Supplemental Disclosure of Cash Flow Information-
Cash paid for interest - DPC only		19,577	4,420
Venoco, Inc.
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	(464,363)	120,437	14,319
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	23,599	44,064	48,840
Ceiling test and other impairments	439,858	817
Accretion of asset retirement obligations	2,150	2,491	2,477
Share-based compensation	498	1,632	754
Interest paid-in-kind	13,749
Amortization of deferred loan costs	3,695	3,268	3,705
Loss (gain) on extinguishment of debt	(67,515)	2,347	38,549
Amortization of bond discounts and other	4,315		698
Unrealized commodity derivative (gains) losses and amortization of premiums	44,403	(101,816)	(15,521)
Changes in operating assets and liabilities:
Accounts receivable	4,302	8,825	11,802
Insurance receivable	(16,500)
Inventories	418	1,796	(65)
Other current assets	818	(258)	(318)
Other assets	(197)	1,758	(1,793)
Accounts payable and accrued liabilities	23,146	413	(29,014)
Share-based compensation liabilities	(2,879)	(34,560)	16,579
Net premiums paid on derivative contracts			(1,495)
Net cash provided by operating activities	9,497	51,214	89,517
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties	(29,405)	(87,660)	(101,995)
Acquisitions of oil and natural gas properties	(21)	(38)	(45)
Expenditures for other property and equipment	(193)	(647)	(2,490)
Proceeds provided by sale of oil and natural gas properties	1,844	196,534	101,077
Net cash (used in) investing activities	(27,775)	108,189	(3,453)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	340,000	182,000	456,900
Principal payments on long-term debt	(155,000)	(322,000)	(716,900)
Payments for deferred loan costs		(871)	(1,260)
Debt issuance costs	(12,423)
Increase in restricted cash	(79,589)
Premium for early retirement of debt			(20,370)
Going private share repurchase costs			(9)
Dividend to Denver Parent Corporation		(3,905)	(15,800)
Denver Parent Corporation capital contribution			158,385
Net cash provided by (used in) financing activities	92,988	(144,776)	(139,054)
Net (decrease) increase in cash and cash equivalents	74,710	14,627	(52,990)
Cash and cash equivalents, beginning of period	15,455	828	53,818
Cash and cash equivalents, end of period	90,165	15,455	828
Supplemental Disclosure of Cash Flow Information-
Cash paid for interest	45,109	52,686	74,880
Supplemental Disclosure of Noncash Activities-
(Decrease) increase in accrued capital expenditures	(785)	(11,223)	(5,789)
Write off of deferred loan costs	3,396	2,347	7,561
Excess of share-based compensation expense recognized over payments made	$ 498	$ 1,632	$ 754

ORGANIZATION AND SUMMARY OF SIG

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2015
ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	1. ORGANIZATION AND SUMMARY OF 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. The consolidated financial statements for Venoco and its consolidated subsidiaries are presented on a separate, stand ‑alone company basis. DPC has engaged in no transactions other than the going private transaction and certain debt transactions, and has incurred no expenses other than interest expenses, deferred loan costs and nominal general and administrative expenses. There are no intercompany sales or expenses between DPC and Venoco. This Annual Report on Form 10 ‑K 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. Principles of Consolidation The consolidated financial statements for DPC include the accounts of DPC and its subsidiaries, all of which are wholly owned. The consolidated financial statements for Venoco include the accounts of Venoco and its subsidiaries, all of which are wholly owned. All intercompany balances and transactions have been eliminated in consolidation. Chapter 11 Proceedings . On March 18, 2016, the Company filed the Chapter 11 cases in the Bankruptcy Court. Debtor-In-Possession . The Company is currently operating the business as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court has granted all of the first day motions filed by the Company that were designed primarily to minimize the impact of the Chapter 11 proceedings on the Company’s operations, customers and employees. As a result, the Company is not only able to conduct normal business activities and pay all associated obligations for the period following its bankruptcy filing, but it is also authorized to pay and has paid (subject to caps applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and vendors providing services and supplies to lease operations , pre-petition amounts owed to pipeline owners that transport the Company’s production, and funds belonging to third parties, including royalty holders and partners. During the pendency of the Chapter 11 case, all transactions outside the ordinary course of our business require the prior approval of the Bankruptcy Court. Automatic Stay . Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Company and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Restructuring Support Agreement . Immediately prior to the Chapter 11 filings, holders of 100% of the Company’s senior secured notes agreed, pursuant to a restructuring support agreement (the “RSA”), to support a plan under which all of the Company’s senior secured notes will be converted to equity. Following the Chapter 11 filings, the Debtors and their pre-petition secured noteholders continued their efforts to reach a consensual deal with holders of Venoco’s unsecured notes. On March 21, 2016, a majority of Venoco’s unsecured noteholders reached an agreement with the Debtors and pre-petition secured noteholders to join the RSA and support the Plan. On April 8, 2016, the Debtors and the other parties to the original RSA agreed to an amended and restated RSA, which provides for a comprehensive financial restructuring of the Debtors’ capital structure under a confirmable chapter 11 plan of reorganization. On April 20, 2016, the Bankruptcy Court approved the Debtors’ assumption of the amended and restated RSA. The other key terms of the restructuring, as contemplated in the RSA, as amended and restated, are as follows: · General Commitments : The RSA commits each of the Restructuring Support Parties to support, and take all reasonable actions necessary to (A) vote all of its claims against the Debtors to accept the Plan in accordance with the applicable procedures (B) timely return a duly-executed ballot in connection therewith; and (C) not “opt out” of any releases under the Plan. In addition, each of the Restructuring Support Parties agrees to support the Plan and not object to the Plan or corresponding disclosure statement. · Milestones : The RSA sets forth the following milestones, the failure of which may result in the termination of the RSA: § Within 45 days of the Petition Date of March 18, 2016 , the Bankruptcy Court must enter a final order approving the DIP Facility (this milestone was satisified on March 22, 2016); § Within 60 days of the Petition Date , the Bankruptcy Court must enter an order approving the RSA (this milestone was satisified on April 20, 2016); § Within 90 days of the Petition Date , the Bankruptcy Court must enter an order approving the Disclosure Statement (this milestone was satisified on May 16, 2016); § Within 150 days of the Petition Date , the Bankruptcy Court must enter an order confirming the Plan ; and § Within 21 days following the date of the order confirming the Plan , the effective date of the Plan must have occurred. The Debtors may extend a milestone with the express prior written consent of a specified percentage of the noteholders . · Commitment of the Debtors : So long as the RSA has not been terminated, each of the Debtors agrees, among other things, to support and take all necessary actions to consummate the Plan in accordance with the terms of the RSA and the milestones contained in the RSA. · Termination Events : The RSA sets forth a number of customary termination events, which, if they occur, could cause the RSA to terminate, including a failure to meet any of the Milestones discussed above. Plan of Reorganization . On April 11, 2016, the Company filed the Plan with the Bankruptcy Court which is supported by the parties to the amended and restated RSA, and a related disclosure statement. The Plan is subject to approval by the Bankruptcy Court. A confirmation hearing on the Plan is scheduled on July 13, 2016 in the Bankruptcy Court. If the Plan is ultimately approved by the Bankruptcy Court, the Company would exit bankruptcy pursuant to the terms of the Plan. Under the Plan, the holders of the Company’s senior secured notes and certain other unsecured creditors, together with the lenders under the debtor-in-possession credit agreement, are to receive 100% of the new common stock to be issued upon emergence of the Company and the Chapter 11 Subsidiaries from bankruptcy, subject to dilution by any shares issuable upon exercise of new warrants to be issued under the Plan. The Plan is subject to acceptance by certain holders of claims against the Company and confirmation by the Bankruptcy Court. The Plan is deemed accepted by a class of claims entitled to vote if at least one-half in number and two-thirds in dollar amount of claims actually voting in the class has voted to accept the Plan. Under certain circumstances set forth in the Bankruptcy Code, the Bankruptcy Court may confirm a plan even if such plan has not been accepted by all impaired classes of claims and equity interests. In particular, a plan may be compelled on a rejecting class if the proponent of the plan demonstrates that (1) no class junior to the rejecting class is receiving or retaining property under the plan and (2) no class of claims or interests senior to the rejecting class is being paid more than in full. Executory Contracts . Subject to certain exceptions, under the Bankruptcy Code the Company may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Company of performing their future obligations under such executory contract or unexpired lease but may give rise to a pre-petition general unsecured claim for damages caused by such deemed breach. Chapter 11 Filing Impact on Creditors and Stockholders . Under the priority requirements established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities to creditors and post-petition liabilities must be satisfied in full before the holders of our existing common stock are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or stockholders, if any, will not be determined until confirmation and implementation of a plan or plans of reorganization. The outcome of the Chapter 11 case remains uncertain at this time and, as a result, we cannot accurately estimate the amounts or value of distributions that creditors and stockholders may receive. It is possible that stockholders will receive no distribution on account of their interests. Debtor-In-Possession Financing . In connection with the Chapter 11 Cases, on March 18, 2016 the Debtors filed a motion seeking Court approval of debtor in possession financing on the terms set forth in a contemplated Superpriority Secured Debtor-in-Possession Credit Agreement (the “ DIP Facility ”). On March 22, 2016, the Debtors (other than Ellwood Pipeline, Inc.) entered into the DIP Facility with certain of the holders of the Company's pre-petition first lien notes, and Wilmington Trust, National Association, as administrative agent (the “Administrative Agent”). The DIP Facility provides for a senior secured superpriority non-amortizing delayed draw term loan facility in an aggregate principal amount of up to $35.0 million. The key terms of the DIP Facility are as follows: · Availability : After entry of the final order approving the DIP Facility, the Company may borrow (a) amounts not exceeding $10.0 million per borrowing, (b) no more t h a n four times during the t e r m of the D I P F ac i l i t y , and ( c ) until t h e California State Lands Commission has approved the LLA, not more than $20.0 million . · DIP Financing Termination Date: The DIP Facility shall terminate on the earliest date to occur of (a) December 31, 2016, (b) 45 days after March 18, 2016 if the Bankruptcy Court has not entered a final order approving the DIP Facility, (c) the substantial consummation of the Plan, (d) the date on which all commitments under the DIP Facility have terminated and all obligations under the DIP Facility have been paid in full in cash and (e) the date on which the commitments under the DIP Facility have been terminated or all or any portion of the loans have been accelerated in accordance with the DIP Facility (such earliest date to occur of the foregoing clauses (a) through (e), the “ DIP Financing Termination Date ”). · Interest Rate : Term Loans will bear interest, at the option of the Company, at (i) 9% plus the Administrative Agent’s base rate, payable monthly in arrears or (ii) 10% plus the current LIBO Rate as quoted by the Administrative Agent for interest periods of one , two , three or six months (the “ LIBO Rate ”), payable at the end of the relevant interest period, but in any event at least quarterly; provided that the Base Rate shall not be less than 2% and the LIBO Rate shall be not less than 1% per annum. · Fees : The fees for the DIP Facility are as follows: § Upfront Fee : For the account of the Lenders, an upfront fee equal to 1.00% of the lenders’ commitment. § Ticking Fee : An unused commitment fee at the rate of 1.00% per annum on the undrawn portion of the DIP Facility. § Backstop Fee : A backstop fee equal to (i) 10% of the common equity of the post-emergence Company issued and outstanding as of the effective date of the Plan, to be due and payable on effectiveness of the Plan, or (ii) in the event the RSA is terminated without the Plan having been consummated, 5.00% of the aggregate principal amount of loans that have been funded, to be due and payable in cash on the later to occur of the (x) the DIP Financing Termination Date and (y) the date of termination of the RSA. · Events of Default : The DIP Facility contains events of default, such as non-payment of required principal and interest, breach of its obligations under the restructuring agreement or change of control. · Budget : On or before the last day of every other calendar week, the Company shall not permit the aggregate amounts (i) for each of certain cash flow forecast line items actually made by the Loan Parties (as defined under the credit agreement for the DIP Facility) in the cash flow forecast during the six -week period ending on the Friday before such day (each such date, a “ Test Date ”) to exceed, on a cumulative basis, the aggregate budgeted amounts set forth in the cash flow forecast in effect for such applicable six -week period for such line item by more than 20% , and (ii) for the aggregate amount of those expenditures in the cash flow forecast actually made by the Loan Parties during the six -week period ending on the Test Date to exceed, on a cumulative basis, the aggregate budgeted amounts set forth in the cash flow forecast in effect for such six -week period for the such items by more than 15% . · Case Milestones : The DIP Facility requires compliance with the following milestones in accordance with the applicable timing (or such later dates as approved by the lenders under the DIP Facility): (a) no later than October 15, 2016, the Bankruptcy Court shall have entered the order for the Plan disclosure statement; (b) no later than December 1, 2016, the Bankruptcy Court shall have entered the order confirming the Plan; and (c) no later than 14 days following the entry of the order confirming the Plan, the Plan shall become effective. Reorganization Expenses . The Company and the Chapter 11 Subsidiaries will incur significant costs associated with the reorganization, principally professional fees. The costs will be expensed as incurred, and are expected to significantly affect our results of operations. In accordance with ASC 852, we will record certain costs associated with the bankruptcy proceedings as Reorganization Items within our Consolidated Statement of Operations. For additional information, see “Reorganization Items” below. Risks Associated with Chapter 11 Proceedings . For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process as described in Item 1A, “Risk Factors.” Because of these risks and uncertainties, the description of our operations, properties and capital plans included in this report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process. Use of Estimates 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. The Company has evaluated subsequent events and transactions for matters that may require recognition or disclosure in these financial statements. Business Segment Information The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, natural gas and natural gas liquids. The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of the Company’s operations and assets are located in the United States, and all of its revenues are attributable to United States customers. Revenue Recognition and Gas Imbalances Revenues from the sale of natural gas and crude oil are recognized when the product is delivered at a fixed or determinable price, title has transferred, collectability is reasonably assured and evidenced by a contract. This generally occurs when oil or natural gas has been delivered to a refinery or a pipeline, or has otherwise been transferred to a customer’s facilities or possession. The Company uses the entitlement method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual production of natural gas. The Company incurs production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under ‑deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over ‑ and under ‑ deliveries or by cash settlement, as required by applicable contracts. The Company’s production imbalances were not material at December 31, 2014 and 2015. Other revenues primarily include pipeline revenues and other miscellaneous revenues. Cash and Cash Equivalents Cash and cash equivalents consist of cash and liquid investments with an original maturity of three months or less. Restricted Cash 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. Accounts Receivable The components of accounts receivable include the following (in thousands): December 31, 2014 2015 Venoco and DPC: Oil and natural gas sales related $ $ Joint interest billings related Realized gains on derivatives Other Allowance for doubtful accounts Venoco total accounts receivable, net $ $ The Company’s accounts receivable result primarily from (i) oil and natural gas sales to large oil refining companies and independent marketers and (ii) billings to joint working interest partners in properties operated by the Company. The Company’s trade and accrued production receivables are spread among limited number of customers and purchasers and most of the Company’s significant purchasers are large companies with solid credit ratings. If customers are considered a credit risk, letters of credit are the primary security obtained to support the extension of credit. For most joint working interest partners, the Company may have the right of offset against related oil and natural gas revenues. As of December 31, 2015, 97% of the oil and natural gas sales related accounts receivable balance was receivable from the Company’s two major customers. The following table provides the percentage of revenue derived from oil and natural gas sales to customers who comprise 10% or more of the Company’s annual revenue (the customers in each year are not necessarily the same from year to year): Years Ended December 31, 2013 2014 2015 Tesoro Refining and Marketing Company % % % ConocoPhillips 66 % % % Insurance Receivable O n March 16, 2016 the Company reached a settlement in the Delaware Litigation, which is further discussed in footnote 12, whereby Venoco and/or the insurers will pay $19 million to be distributed to the class. As part of the settlement the insurance companies have signed the Insurance Settlement which states that they will pay $16.5 million of the $19 million Litigation Settlement amount. As a result of the Litigation Settlement, $19 million was recorded in the balance sheet within Accounts Payable and Accrued Liabilities, with $16.5 million recorded as a receivable, as it is an insurance recovery to be received pursuant to the Insurance Settlement. The portion that the Company will ultimately owe is $2.5 million which is recorded in the statement of operations within General and Administrative Expenses. Inventories Included in inventories are oil field materials and supplies, stated at the lower of cost or market, cost being determined by the first ‑ in, first ‑out method. Oil and Natural Gas Properties The Company’s oil and natural gas producing activities are accounted for using the full cost method of accounting. Accordingly, the Company capitalizes all costs incurred in connection with the acquisition of oil and natural gas properties and with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as adjustments to the full cost pool, with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. Depletion of the capitalized costs of oil and natural gas properties, including estimated future development and abandonment costs, is provided for using the equivalent unit ‑of ‑production method based upon estimates of proved oil and natural gas reserves. Depletion expense for the years ended December 31, 2013, 2014 and 2015 was $46.0 million, $42.0 million and $22.0 million, respectively. Unproved property costs not subject to amortization consist primarily of leasehold and seismic costs related to unproved areas. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. The Company transferred $4.0 million and $8.6 million of unproved costs into the amortization base in 2013 and 2015, respectively, due to impairment, development of acreage or placement of assets into service. No interest costs were capitalized in 2013, 2014 or 2015 because the Company did not have any unusually significant investments in unproved properties that qualify for interest capitalization. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are subject to a ceiling based upon the related estimated future net revenues, discounted at 10 percent, net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. The Company did not record an impairment of oil and natural gas properties in 2013. In 2014, the Company recorded $0.8 million impairment of a prospect in Argentina. In 2015 the Company recorded a $437.5 million impairment due to ceiling test limitations. The impairment was primarily due 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 could 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 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. Accounts Payable and Accrued Liabilities The components of accounts payable and accrued liabilities include the following. December 31, 2014 2015 Venoco and DPC: Accounts Payable $ $ Accrued Liabilities Accrued Liabilities - Delaware Settlement — Accrued Payroll and Bonus Accrued Taxes Notes payable Revenue and Severance tax payable Other General and Administrative Expenses Under the full cost method of accounting, the Company capitalizes a portion of general and administrative expenses that are directly identified with exploration, exploitation and development activities. These capitalized costs include salaries, employee benefits, costs of consulting services and other specifically identifiable costs and do not include costs related to production operations, general corporate overhead or similar activities. The Company capitalized general and administrative costs of $ 23.0 million, $8.7 million and $ 9.0 million directly related to its exploration, exploitation and development activities during 2013, 2014 and 2015, respectively. Other Property and Equipment Other property and equipment, which includes land, drilling equipment, leasehold improvements, office and other equipment, are stated at cost. Depreciation and amortization are calculated using the straight ‑line method over the estimated useful lives of the related assets, ranging from 3 to 25 years. Depreciation and amortization expense for the years ended December 31, 2013, 2014 and 2015 was $2.8 million, $2. 1 million and $1.6 million, respectively. Derivative Financial Instruments From time to time the Company enters into derivative contracts, primarily collars, swaps and option contracts, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivative instruments are recorded on the balance sheet at fair value. The Company has elected not to apply hedge accounting to any of its derivative transactions and, consequently, the Company recognizes mark ‑to ‑market gains and losses in earnings currently, rather than deferring such amounts in other comprehensive income for those commodity derivatives that qualify as cash flow hedges. Deferred Loan Costs In 2015 the Company changed the manner in which it reports debt issuance costs due to adoption of ASU No. 2015-03, “Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” (“ASU 2015-03”). Debt issuance costs related to a recognized debt liability previously reported as assets have been reclassified as a direct deduction from the carrying amount of debt liabilities in the Company’s consolidated financial statements in all periods presented. The effects of the standard were applied retrospectively to all prior interim and annual periods within this annual report. The effect of the change in accounting principle as of December 31, 2015 and December 31, 2014 , was that $10.6 million and $7.1 million, respectively, of Venoco’s deferred loan costs have been reclassified from other assets to debt on the Company’s consolidated financial statements. Additionally, as of December 31, 2015 and December 31, 2014 $13.6 million and $11.6 million, respectively, of deferred loan costs have been reclassifed for DPC. Asset Retirement Obligations The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and natural gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long ‑lived asset are recorded at the time the well is spud or acquired. Environmental The Company is subject to extensive federal, state and local environmental laws and regulations. These laws and regulations, which regularly change, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non ‑capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally recorded at their undiscounted amounts unless the amount and timing of payments is fixed or reliably determinable. The Company believes that it is in material compliance with existing laws and regulations. Other Employee Benefit Plans The Company sponsors a 401(k) tax deferred savings plan (the 401(k) Plan) and makes it available to employees. The 401(k)Plan is a defined contribution plan, and the Company may make discretionary matching contributions of up to 90% of their annual compensation, not to exceed contribution limits established by the Internal Revenue Code. The Company makes matching contributions of 100% of participant contributions on the first 5% of compensation and 50% of participant contribution thereafter. The contributions made by the Company totaled approximately $2.0 million, $ 1.7 million and $1.3 million during the years ended December 31, 2013, 2014, and 2015, respectively. Share ‑Based Compensation Share ‑based compensation for equity awards is measured at the estimated grant date fair value of the awards and is recognized over the requisite service period (usually the vesting period). The Company estimates forfeitures in calculating the cost related to share ‑based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur. Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered. A market condition is not considered to be a vesting condition with respect to compensation expense. Therefore, an award is not deemed to be forfeited solely because a market condition is not satisfied. The Company measures its liability awards based on the award’s fair value remeasured at each reporting date until the date of settlement. Compensation cost for each period until settlement is based on the change (or a portion of the change, depending on the percentage of the requisite service that has been rendered at the reporting date). Changes in the fair value of a liability that occur after the end of the requisite service period are compensation cost of the period in which the changes occur. Any difference between the amount for which a liability award is settled and its fair value at the settlement date is an adjustment of compensation cost in the period of settlement. Income Taxes In 2015, the Company changed

SALES OF PROPERTIES

SALES OF PROPERTIES	12 Months Ended
	Dec. 31, 2015
SALES OF PROPERTIES
SALES OF PROPERTIES	2. SALES OF PROPERTIES Sale of Montalvo Assets. Effective July 1, 2014, the Company sold the Montalvo field to Vintage Petroleum, LLC for $200.2 million. The Company applied 100% of the net proceeds to reduce the principal balance outstanding on its revolving credit facility. No gain or loss was recognized on the sale as the Company recorded the net proceeds as a reduction to the capitalized costs of its oil and natural gas properties.

DEBT

DEBT	12 Months Ended
	Dec. 31, 2015
DEBT
DEBT	3. DEBT As of the dates indicated, the Company’s debt consisted of the following (in thousands): Venoco, Inc. Denver Parent Corporation December 31, December 31, December 31, December 31, 2014 2015 2014 2015 Venoco revolving credit agreement due March 2016 $ $ — $ $ — Venoco 8.875% senior notes due February 2019 First lien secured 12% notes due February 2019 — — Second lien secured 8.875% / 12% PIK notes due February 2019(1) — — Term loan facility due December 2017(2) — — DPC 12.25% / 13.00% senior PIK toggle notes due August 2018(3) — — Deferred Loan Costs Total long-term debt Less: current portion of long-term debt — — Long-term debt, net of current portion $ $ — $ $ — (1) Amounts are net of $24.2 million unamortized discount at December 31, 2015. Amounts include $9.3 million of accrued PIK interest not yet capitalized. (2) Amounts are net of $0.6 million unamortized discount at December 31, 2015. (3) Amounts are net of $4 .0 million and $5.4 million unamortized discount at December 31, 2015 and December 31, 2014, respectively. Amounts include $14.8 million and $13.0 million of accrued PIK interest not yet capitalized at December 31, 2015 and December 31, 2014, respectively. 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”). The term loan facility was refinanced on June 11, 2015. 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 following summarizes the terms of the agreements governing the Company’s debt outstanding as of December 31, 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 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. 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. 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 (terminated as of the date of this report). The term loan facility, which was fully drawn at closing, matures in December 2017. Amounts borrowed under the facility 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. On March 25, 2016 the term loan facility was repaid in full using the cash collateral which secured the note. 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 December 31, 2015, $308.2 million principal amount of 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 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 subsequent 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 redeem the notes, in whole or in part, at any time prior to August 15, 2015, at a “make ‑whole” redemption price described in the indenture. DPC may also redeem all or any part of 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 our ability to make investments, incur additional indebtedness, issue preferred stock, pay dividends, repurchase stock, create liens or sell assets. Interest expense for DPC only during the years ended December 31, 2013, 2014, and 2015 were $21.5 million, $34.4 million and $39.1 million, respectively. 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 issuance costs related to 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 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. Scheduled annual maturities of debt outstanding as of December 31, 2015 were as follows (in thousands): Denver Parent Year Ending December 31, (in thousands): Venoco, Inc. Corporation 2016 $ — $ — 2017 2018 — 2019 2020 — — Thereafter — — $ $

HEDGING AND DERIVATIVE FINANCIA

HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2015
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS	4. 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 consolidated statements of operations are as follows (in thousands): 2013 2014 2015 Realized commodity derivative losses (gains) $ $ $ Unrealized commodity derivative losses (gains) for changes in fair value Commodity derivative losses (gains), net $ $ $ As of December 31, 2015, the Company had entered into certain swap 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) Weighted Avg. Barrels/day Prices per Bbl January 1 - December 31, 2016: Swaps $ On February 11, 2016 the Company terminated its final derivative contract with Bank of America. The cash proceeds of the terminated derivative was $34.6 million. Fair Value of Derivative Instruments. The estimated fair values of derivatives included in the consolidated balance sheets at December 31, 2014 and 2015 are summarized below. 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, December 31, 2014 2015 Current Assets—Commodity derivatives: Oil derivative contracts $ $ Noncurrent Assets—Commodity derivatives: Oil derivative contracts — Net derivative asset $ $

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2015
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS	5. ASSET RETIREMENT OBLIGATIONS The Company’s asset retirement obligations represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut ‑in properties (including removal of certain onshore and offshore facilities) at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its asset retirement obligations when incurred by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units ‑of ‑production method. The following table summarizes the activities for the Company’s asset retirement obligations for the years ended December 31, 2014 and 2015 (in thousands): 2014 2015 Asset retirement obligations at beginning of period $ $ Revisions of estimated liabilities Liabilities incurred or acquired — Liabilities settled or disposed Accretion expense Asset retirement obligations at end of period Less: current asset retirement obligations (classified with accounts payable and accrued liabilities) Long-term asset retirement obligations $ $ The liabilities settled or disposed of $ 9.4 million for 2014 primarily relate to the Montalvo asset sale.

CAPITAL STOCK

CAPITAL STOCK	12 Months Ended
	Dec. 31, 2015
CAPITAL STOCK
CAPITAL STOCK	6. CAPITAL STOCK The going private transaction was completed in October 2012. As a result of the transaction, Venoco’s common stock is no longer publicly traded and Venoco is wholly owned by DPC, an entity controlled by Timothy Marquez and his affiliates. At closing, all then ‑outstanding shares of Venoco common stock, other than shares beneficially owned by Mr. Marquez, were converted into the right to receive cash of $12.50 per share pursuant to the terms of the merger agreement. During 2014, DPC issued 146,525 shares to its Employee Stock Ownership Plan (“ESOP”). As of December 31, 2015, there were 30,297,459 shares of common stock of DPC and 29,936,378 shares of common stock of Venoco outstanding. No stock grants were made in 2015.

SHARE-BASED PAYMENTS

SHARE-BASED PAYMENTS	12 Months Ended
	Dec. 31, 2015
SHARE-BASED PAYMENTS
SHARE-BASED PAYMENTS	7. SHARE ‑BASED PAYMENTS In connection with the going private transaction, all of the Company’s equity awards were converted into cash settlement awards as follows: · All previously granted stock option awards, which had a maximum life of ten years, were fully vested at December 31, 2011. Holders of in ‑the ‑ money options were paid the difference between $12.50 per share and the original exercise price and replacement share appreciation rights (SARs) were granted to these holders with an exercise price of $12.50 per share. Holders of options with an original exercise price greater than $12.50 were cancelled and replacement SARs were granted at the original exercise price. These SAR awards are 100% vested on the grant date and retain the original option award termination date. After the going private transaction, the Company granted the following cash settlement or liability awards to officers, directors and certain employees of the Company: · Restricted share unit awards (RSUs) that generally vest over a four year service period beginning April 1, 2013. At each vesting date, holders of the RSUs are paid the fair value of DPC common stock. The estimated fair value of the award is recognized as expense over the requisite service period and fair values are remeasured for unvested awards at each reporting date until the date of settlement. Certain grants of RSUs to officers and directors vest based on achievement of performance measurements used to determine the Company’s annual cash bonus payout and related expense is recognized using graded vesting resulting in more accelerated expense recognition than expense recognized using straight line vesting over the service period. · SAR awards with an exercise price of $12.50 per share for each unvested rights-to-receive awards (RTR), subject to the original service conditions of the RTR. Compensation expense is recognized based on the grant date fair values over the remaining requisite service period of the RTR and these awards have a ten year life from the date of grant. · SAR awards for each Venoco common share held at the date of the going private transaction (except for the Company’s Executive Chairman) with an exercise price of $12.50 per unit. All such SAR awards are 100% vested on the grant date and have a ten year life from the date of grant. The Company adopted an ESOP effective December 31, 2012 for eligible employees who are actively employed on the last day of the plan year. For each plan year, beginning in 2013, the Company will make discretionary contributions of restricted share units in DPC common stock to the ESOP based on a portion of the participant’s eligible compensation, subject to certain Internal Revenue Code limitations. The number of ESOP restricted share units in DPC common stock granted to each participant is based on the total amount of the discretionary contribution to the participant each year, divided by the fair market value of DPC common stock on the valuation date as determined by an independent appraiser. ESOP restricted share units generally vest over a four year period beginning with the participant’s hire date or the date of the adoption of the ESOP, whichever is later. The value of participants’ accounts is determined based on an appraisal, performed at least annually, of the fair market value of DPC common stock. Participants may begin making withdrawals from the vested portion of their accounts upon separation from the Company or upon reaching normal retirement age as determined by the Internal Revenue Code. The following summarizes the Company’s cash settlement awards activity during the year ended December 31, 2015: Share Employee Stock Restricted Share Units Appreciation Rights Aggregate Ownership Plan Weighted Weighted Intrinsic Weighted Rights to Receive Average Average Value of Average Cash Grant-Date Grant-Date SARs Grant-Date Units Value Units Fair Value Units Fair Value Exercisable Units Fair Value Outstanding, end of period, December 31, 2013 Granted — — Vested or exercised — — Cancelled and other Exercisable, end of period — — $ — — Outstanding, end of period, December 31, 2014 $ $ $ $ Vested or exercised — Cancelled and other Exercisable, end of period — — $ — — Outstanding, end of period, December 31, 2015 Additional information related to SARs outstanding at December 31, 2015 is as follows: SARs Outstanding SARs Exercisable Weighted Weighted Average Weighted- Average Weighted Remaining Average Remaining Average Number Contractual Exercise Number Contractual Exercise Range of Exercise Prices Outstanding Life Prices Exercisable Life Prices $ 8.33 $ $ $ 12.24 $ $ $ 12.50 $ $ $ - $ 20.00 $ $ $ $ The grant date fair value of each SAR is estimated using the Black ‑Scholes valuation model. Valuation models require the input of highly subjective assumptions, including the expected volatility of the price of the underlying stock. The Company’s units have characteristics significantly different from those of traded units, and because changes in the subjective input assumptions can materially affect the fair value estimate, it is management’s opinion that the valuations afforded by existing models are different from the value that the units would realize if traded in the market. The following assumptions were used to compute the grant date fair value of SARs at: December 31, 2014 Expected lives - years Risk free interest rates % - % Estimated volatilities % - % Dividend yield % No SARs were granted in 2015. The Company calculated the expected life of units when granted using the “simplified method” set forth in Staff Accounting Bulletin 107 (average of vesting period and term of the option). For deep out ‑of ‑the ‑money SARs where the derived service period is materially longer than the explicit service period, the requisite service period is based on the derived service period. The risk free interest rate was based on the U.S. Treasury yield curve in effect at the time of grant. The expected volatility was based on the historical volatility of public companies with characteristics similar to the Company for the past seven years. The Company measures its liability awards based on the award’s fair value remeasured at each reporting date until the date of settlement. Compensation cost for each period until settlement is based on the change (or a portion of the change, depending on the percentage of the requisite service that has been rendered at the reporting date). Changes in the fair value of a liability that occur after the end of the requisite service period are compensation cost of the period in which the changes occur. Any difference between the amount for which a liability award is settled and its fair value at the settlement date is an adjustment of compensation cost in the period of settlement. The following table summarizes Company’s share ‑based compensation liability at (in thousands): December 31, December 31, 2014 2015 Share-based compensation liability at beginning of period $ $ Total share-based compensation costs (income) Payouts APIC adjustment Share-based compensation liability at end of period Less: current share-based compensation liability Long-term share-based compensation liability $ $ The following summarizes the composition of the share ‑based compensation liability at (in thousands): December 31, 2014 December 31, 2015 Current Long Term Total Current Long Term Total Liability Liability Liability Liability Liability Liability Rights to receive $ $ — $ $ $ — $ Restricted share units — — Share appreciation rights — — — — ESOP — — Total share-based compensation liability $ $ $ $ $ $ The Company recognized total share ‑based compensation costs as follows (in thousands): Years Ended December 31, 2013 2014 2015 General and administrative expense (income) $ $ $ Oil and natural gas production expense (income) Total share-based compensation costs (income) Less: share-based compensation costs capitalized (reduced) Share-based compensation expense (income) $ $ $

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2015
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS	8. FAIR VALUE MEASUREMENTS Fair value is defined as the price that would be received in the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. The FASB has established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy are as follows: Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2—Pricing inputs are other than quoted prices in active markets included in level 1, but are either directly or indirectly observable as of the reported date and for substantially the full term of the instrument. Inputs may include quoted prices for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of December 31, 2015 (in thousands). Fair Value as of December 31, Level 1 Level 2 Level 3 2015 Assets (Liabilities): Commodity derivative contracts $ — $ $ — $ Share-based compensation — — Derivative Insturments. Typically, 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. 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): Year Ended December 31, 2014 2015 Fair value liability, beginning of period $ $ Transfers into Level 3(1) Transfers out of Level 3(2) Change in fair value of Level 3 Fair value liability, end of period $ $ (1) The transfers into Level 3 liability during 2014 and 2015 relate to RSU, SAR and ESOP requisite service period expense. (2) The transfers out of Level 3 liability during 2015 relate to cash settlements of RSU grants, and forfeitures of RSU, SAR and ESOP grants as a result of employee terminations. Fair Value of Financial Instruments. The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable and payable, derivatives (discussed above) and long-term debt. The carrying values of cash equivalents and accounts receivable and payable are representative of their fair values due to their short-term maturities. The carrying amount of Venoco’s revolving credit facility 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 data and valuation techniques (Level 2) to estimate the fair value of the first lien and second lien notes. This disclosure does not impact our financial position, results of operations or cash flows (in thousands) . December 31, 2014 December 31, 2015 Carrying Estimated Carrying Estimated Value Fair Value Value Fair Value Venoco: Revolving credit agreement $ $ $ — $ — Venoco 8.875% senior notes due February 2019 First lien secured 12% notes due February 2019 — — Second lien secured 8.875% / 12% PIK notes due February 2019 (1) — — Term loan facility due December 2017 — — Denver Parent Corporation: 12.25% / 13.00% senior PIK toggle notes (2) (1) Amounts include $9.3 million of accrued PIK interest not yet capitalized. (2) Amounts include $14.8 million of accrued PIK interest not yet capitalized .

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2015
INCOME TAXES
INCOME TAXES	9. INCOME TAXES The Company accounts for income taxes under the asset and liability approach, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company’s consolidated financial statements or tax returns. Beginning with the 2012 calendar year, DPC files consolidated federal and state income tax returns including the operating results of Venoco. The income tax provisions for DPC and Venoco have been prepared on a separate return basis. DPC and Venoco did not have a current or deferred income tax expense or benefit in each of the years presented since each has a full valuation allowance against its net deferred tax assets in 2013, 2014 and 2015. As of December 31, 2015, DPC has net operating loss carryovers (“NOLs”) of $557 million for federal income tax purposes and $ 517 million for financial reporting purposes, and Venoco has net NOLs as of December 31, 2015 of $4 35 million for federal income tax purposes and $3 95 million for financial reporting purposes. The difference between the federal income tax NOLs and the financial reporting NOLs of $40 million 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 2035. Venoco has incurred losses before income taxes in 2008, 2009, and 2012 as well as taxable losses in each of the tax years from 2008 through 2013 and 2015. DPC has incurred losses before income taxes in 2008, 2009, 2012, 2013, 2014 and 2015 as well as taxable losses in each of the tax years from 2008 through 2015. These losses and expected future taxable losses were a key consideration that led Venoco and DPC to provide a full valuation allowance against its net deferred tax assets as of December 31, 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 CO 2 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 or for state income taxes. A reconciliation of the income tax provision (benefit) computed by applying the federal statutory rate of 35% to the Company’s income tax provision (benefit) is as follows (in thousands): Venoco, Inc. Denver Parent Corporation Years Ended December 31, Years Ended December 31, 2013 2014 2015 2013 2014 2015 Income tax expense (benefit) at federal statutory rate $ $ $ $ $ $ State income tax expense (benefit) Other Valuation allowance $ — $ — $ — $ — $ — $ — The components of deferred tax assets and (liabilities) are as follows (in thousands): Venoco, Inc. Denver Parent Corporation December 31, December 31, December 31, December 31, 2014 2015 2014 2015 Deferred income tax assets: Net operating losses $ $ $ $ Oil and gas properties — — Accrued liabilities Share-based compensation Charitable contributions Other current assets Asset retirement obligations Alternative minimum tax credits Valuation allowance Deferred income tax liabilities: Oil and gas properties — — Unrealized commodity derivative gains Prepaid expenses Investments Net deferred income tax assets (liabilities) $ — $ — $ — $ — The Company’s 2009 through 2014 tax years remain open to examination by the U.S. Internal Revenue Service (“IRS”). The Company is not currently under examination by the IRS. The Company’s 2007 through 2014 tax years remain open to examination by the various state jurisdictions. The Company is not currently under examination by any state jurisdictions. Due to the finalization of the 2003 through 2008 IRS examinations, the NOL carryback claims filed with the IRS, the finalization of the 2003 and 2004 FTB examinations and analysis of tax positions taken on tax returns following these examinations, the Company believes that it has no liability for uncertain tax positions.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2015
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS	10. RELATED PARTY TRANSACTIONS In 2006, the Company paid a dividend consisting of 100% of its membership interest in 6267 Carpinteria Avenue, LLC (“6267 Carpinteria”) to its then sole stockholder, a trust controlled by Timothy Marquez, the Company’s then ‑ Chairman and CEO. 6267 Carpinteria owns the office building and related land used by the Company in Carpinteria, California. The Company made lease payments to 6267 Carpinteria under a lease for the office building entered into prior to the dividend. In March 2013, the building was sold to an independent third party, and the lease terms were modified at closing under similar terms through 2023. The Company made minimum lease payments of approximately $0.2 million 6267 Carpinteria in 2013. 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 $0.7 million, $0.7 million and $ 0.6 million in 2013, 2014 and 2015, respectively. The sublease agreement expired on December 31, 2015 and was not renewed.

COMMITMENTS

COMMITMENTS	12 Months Ended
	Dec. 31, 2015
COMMITMENTS
COMMITMENTS	11. COMMITMENTS Leases —The Company has entered into lease agreements for office space, an office building, and a parcel of land adjacent to the Ellwood pier used for pier access. As of December 31, 2015, future minimum lease payments under operating leases that have initial or remaining non-cancelable terms in excess of one year are $1.9 million in 2016, $1.9 million in 2017, $2.2 million in 2018, $2. 5 million in 2019, $2. 4 million in 2020 and $5.1 million thereafter. Net rent expense incurred for office space and the office building was $2.0 million, $1.7 million and $1.5 million in 2013, 2014 and 2015, respectively.

CONTINGENCIES

CONTINGENCIES	12 Months Ended
	Dec. 31, 2015
CONTINGENCIES
CONTINGENCIES	12. 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 affect 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 result of the breach of fiduciary duties by the defendants. The Colorado actions have been administratively closed pending resolution of the Delaware case. An Insurance Settlement Agreement and Release between all of Venoco’s Director & Officer insurance carriers and all defendants (“Insurance Settlement”) was executed on March 16, 2016. A Stipulation and Agreement of Compromise and Settlement between plaintiffs and defendants (“Litigation Settlement”) was also executed and filed with the Delaware Chancery Court. A hearing in that court to approve the Litigation Settlement is scheduled for July 27, 2016. The Litigation Settlement states that Venoco and/or the insurers will pay $19 million to be distributed to the class. The Insurance Settlement states that the insurers will pay $16.5 million of the $19 million Litigation Settlement amount. As a result of the Litigation Settlement, $19 million was recorded in the balance sheet within Accounts Payable and Accrued Liabilities, with $16.5 million recorded as a receivable, as it is an insurance recovery to be received pursuant to the Insurance Settlement. The portion that the Company will ultimately owe is $2.5 million which is recorded in the statement of operations within General and Administrative Expenses. 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 TexCal’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. On March 28, 2016, TexCal filed a Notice of Bankruptcy Stay. Plains Pipeline – On May 19, 2015, the Plains All American Pipeline (“Plains”) Line 901 that transports oil production from Platform Holly in the South Ellwood field ruptured, resulting in a spill near Refugio Beach State Park. Line 901 is currently inoperable due to the spill and related ongoing repairs. As a result, Venoco has been forced to halt production activities at Platform Holly in response to the incident. Venoco filed a claim against Plains in Superior Court of California, Santa Barbara County, on April 1, 2016. On May 2, 2016, Plains filed a Notice of Removal of Action with the U.S. District Court, Central District of California. 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.

QUARTERLY FINANCIAL DATA (UNAUD

QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
	Dec. 31, 2015
QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTERLY FINANCIAL DATA (UNAUDITED)	13. QUARTERLY FINANCIAL DATA (UNAUDITED) The following is a summary of the unaudited financial data for each quarter for the years ended December 31, 2014 and 2015 (in thousands): Venoco, Inc. Denver Parent Corporation Three Months Ended Three Months Ended March 31, June 30, September 30, December 31, March 31, June 30, September 30, December 31, 2014 2014 2014 2014 2014 2014 2014 2014 Year Ended December 31, 2014 Revenues $ $ $ $ $ $ $ $ Income (loss) from operations Net income (loss) Venoco, Inc. Denver Parent Corporation Three Months Ended Three Months Ended March 31, June 30, September 30, December 31, March 31, June 30, September 30, December 31, 2015 2015 2015 2015 2015 2015 2015 2015 Year Ended December 31, 2015 Revenues $ $ $ $ $ $ $ $ Income (loss) from operations Net income (loss)

SUPPLEMENTAL INFORMATION ON OIL

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2015
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)	14. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) The following information concerning the Company’s natural gas and oil operations has been provided pursuant to the FASB guidance regarding Oil and Gas Reserve Estimation and Disclosures. At December 31, 2015, the Company’s oil and natural gas producing activities were conducted onshore within the continental United States and offshore in federal and state waters off the coast of California. The evaluations of the oil and natural gas reserves at December 31, 2013, 2014 and 2015 were prepared by DeGolyer and MacNaughton, independent petroleum reserve engineers. Capitalized Costs of Oil and Natural Gas Properties As of December 31, 2013 2014 2015 (in thousands) Unevaluated properties $ $ $ — Properties subject to amortization Total capitalized costs Accumulated depletion(1) Net capitalized costs $ $ $ (1) Depletion expense for the years ended December 31, 2013, 2014 and 2015 was $46.0 million, $42.0 million and $22.0 million, respectively ( $13.2 7 , $15.54 and $15.15 , respectively, per equivalent barrel of oil). Capitalized Costs Incurred Costs incurred for oil and natural gas exploration, development and acquisition are summarized below. Costs incurred during the years ended December 31, 2013, 2014 and 2015 include capitalized general and administrative costs related to acquisition, exploration and development of natural gas and oil properties of $23.0 million, $8.7 million and $9.0 million, respectively. Costs incurred also include asset retirement costs of $0.5 million, $4.6 million and $ 1.3 million recorded during the years ended December 31, 2013, 2014 and 2015, respectively. Years Ended December 31, 2013 2014 2015 (in thousands) Property acquisition and leasehold costs: Unevaluated property $ $ $ — Proved property Exploration costs Development costs Total costs incurred $ $ $ Estimated Net Quantities of Natural Gas and Oil Reserves The following table sets forth the Company’s net proved reserves, including changes, proved developed reserves and proved undeveloped reserves (all within the United States) at the end of each of the three years in the periods ended December 31, 2013, 2014 and 2015. Crude Oil, Liquids and Condensate (MBbls)(4) Natural Gas (MMcf) 2013(1) 2014(2) 2015(3) 2013(1) 2014(2) 2015(3) Beginning of the year reserves Revisions of previous estimates Extensions and discoveries(5) — — — Purchases of reserves in place — — — — — — Production Sales of reserves in place — — — — End of year reserves Proved developed reserves: Beginning of year End of year Proved undeveloped reserves: Beginning of year End of year — — (1) Unescalated twelve month arithmetic average of the first day of the month posted prices of $96.78 per Bbl for oil and natural gas liquids and $3.67 per MMBtu for natural gas were adjusted for quality, energy content, transportation fees and regional price differentials to arrive at realized prices of $98.37 per Bbl for oil, $79.04 per Bbl for natural gas liquids and $4.41 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2013. (2) Unescalated twelve month arithmetic average of the first day of the month posted prices of $94.99 per Bbl for oil and natural gas liquids and $4.35 per MMBtu for natural gas were adjusted as in note (1) above to arrive at realized prices of $86.69 per Bbl for oil, $71.12 per Bbl for natural gas liquids and $5.21 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2014. (3) Unescalated twelve month arithmetic average of the first day of the month posted prices of $50.28 per Bbl for oil and natural gas liquids and $2.58 per MMBtu for natural gas were adjusted as in note (1) above to arrive at realized prices of $38. 32 per Bbl for oil, $32.28 per Bbl for natural gas liquids and $2.96 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2015. (4) Natural gas liquids reserves represent a minimal percentage of our total reserves (approximately 3.4% , 3.8% and 5.8% at December 31, 2013, 2014 and 2015, respectively), therefore natural gas liquids are not presented separately but rather are included with oil volumes. (5) Extensions for the year ended December 31, 2013 represent results from the drilling at the South Ellwood field of the Coal Oil Point well and the addition of reserves for two additional undeveloped locations. Extensions for the year ended December 31, 2014 represent results from the drilling of a M2 infill well at Sockeye. Uncertainties with respect to future acquisition and development of reserves include (i) the success of development programs, including potential changes to the Company’s drilling schedule based on ongoing operational results, (ii) the ability to obtain permits from relevant regulatory bodies to pursue development projects, (iii) changes in commodity prices, and (iv) the availability of sufficient cash flow from operations or external financing to fund the capital expenditure program. In addition, the Company has reversionary interest in the Hastings Complex CO 2 project, which will be subject to a significant degree of variability until Denbury has recovered all of its costs as defined in the agreement and the Company is able to back in to its 22.45% working interest. The amount of reserves and resulting production necessary for Denbury to recover its costs will be determined in large part by such factors as the existing commodity price and operating cost environment Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves The following summarizes the policies used in the preparation of the accompanying oil and natural gas reserve disclosures, standardized measures of discounted future net cash flows from proved oil and natural gas reserves and the reconciliations of standardized measures from year to year. The information disclosed, as prescribed by the Oil and Gas Reserve Estimation and Disclosure guidance issued by the FASB, is an attempt to present the information in a manner comparable with industry peers. The information is based on estimates of proved reserves attributable to the Company’s interest in oil and natural gas properties as of December 31 of the years presented. These estimates were prepared by independent petroleum reserve engineers. Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (1) Estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year ‑end economic conditions. (2) The estimated future cash flows are compiled by applying the twelve month average of the first of the month prices of crude oil and natural gas relating to the Company’s proved reserves to the year ‑end quantities of those reserves as of December 31, 2013, 2014 and 2015. (3) The future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year ‑end economic conditions. (4) Future income tax expenses are based on year ‑end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits and allowances relating to the Company’s proved oil and natural gas reserves. (5) Future net cash flows are discounted to present value by applying a discount rate of 10% . The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows and does not include cash flows associated with hedges outstanding at each of the respective reporting dates. As of December 31, 2013 2014 2015 (in thousands) Future cash inflows $ $ $ Future production costs Future development and abandonment costs Future income taxes — Future net cash flows 10% annual discount for estimated timing of cash flows Standardized measure of discounted future net cash flows $ $ $ The following table summarizes changes in the standardized measure of discounted future net cash flows. Years Ended December 31, 2013 2014 2015 (in thousands) Beginning of the year $ $ $ Changes in prices and production costs Revisions of previous quantity estimates Changes in future development costs Development costs incurred during the period Extensions, discoveries and improved recovery, net of related costs — Sales of oil and natural gas, net of production costs Accretion of discount Net change in income taxes Sale of reserves in place — — Purchases of reserves in place — — — Production timing and other End of year $ $ $

GUARANTOR FINANCIAL INFORMATION

GUARANTOR FINANCIAL INFORMATION	12 Months Ended
	Dec. 31, 2015
GUARANTOR FINANCIAL INFORMATION
GUARANTOR FINANCIAL INFORMATION	15. 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. 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 December 31, 2015 . All Guarantors are 100% owned by the Company. Presented below are the Company’s condensed consolidating balance sheets, statements of operations and statements of cash flows as required by Rule 3 ‑10 of Regulation S ‑X of the Securities Exchange Act of 1934. There are currently no guarantors of DPC’s 12.25% / 13.00% senior PIK toggle notes. CONDENSED CONSOLIDATING BALANCE SHEETS AT DECEMBER 31, 2014 (in thousands) Non- Guarantor Guarantor Venoco, Inc. Subsidiaries Subsidiary Eliminations Consolidated ASSETS CURRENT ASSETS: Cash and cash equivalents $ $ — $ — $ — $ Accounts receivable — Inventories — — — Other current assets — — — Commodity derivatives — — — TOTAL CURRENT ASSETS — PROPERTY, PLANT & EQUIPMENT, NET — COMMODITY DERIVATIVES — — — INVESTMENTS IN AFFILIATES — — — OTHER — — TOTAL ASSETS LIABILITIES AND STOCKHOLDERS’ EQUITY CURRENT LIABILITIES: Accounts payable and accrued liabilities — — — Interest payable — — — Share-based compensation — — — TOTAL CURRENT LIABILITIES: — — — LONG-TERM DEBT — — — COMMODITY DERIVATIVES — — — — — ASSET RETIREMENT OBLIGATIONS — SHARE-BASED COMPENSATION — — — INTERCOMPANY PAYABLES (RECEIVABLES) — TOTAL LIABILITIES TOTAL STOCKHOLDERS’ EQUITY (DEFICIT) TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) $ $ $ $ $ CONDENSED CONSOLIDATING BALANCE SHEETS AT DECEMBER 31, 2015 (in thousands) Non- Guarantor Guarantor Venoco, Inc. Subsidiaries Subsidiary Eliminations Consolidated ASSETS CURRENT ASSETS: Cash and cash equivalents $ $ — $ — $ — $ Restricted funds — — — Accounts receivable — Insurance receivable — — — Inventories — — — Other current assets — — — Commodity derivatives — — — TOTAL CURRENT ASSETS — PROPERTY, PLANT & EQUIPMENT, NET — COMMODITY DERIVATIVES — — — — — INVESTMENTS IN AFFILIATES — — — OTHER — — TOTAL ASSETS LIABILITIES AND STOCKHOLDERS’ EQUITY CURRENT LIABILITIES: Accounts payable and accrued liabilities — — — Interest payable — — — Share-based compensation — — — CURRENT PORTION OF LONG-TERM DEBT — — — TOTAL CURRENT LIABILITIES: — — — COMMODITY DERIVATIVES — — — — — ASSET RETIREMENT OBLIGATIONS — SHARE-BASED COMPENSATION — — — INTERCOMPANY PAYABLES (RECEIVABLES) — TOTAL LIABILITIES TOTAL STOCKHOLDERS’ EQUITY (DEFICIT) TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) $ $ $ $ $ CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS AT DECEMBER 31, 2013 (in thousands) Guarantor Non-Guarantor Venoco, Inc. Subsidiaries Subsidiary Eliminations Consolidated REVENUES: Oil and natural gas sales $ $ $ — $ — $ Other — Total revenues EXPENSES: Lease operating expense — Production and property taxes — Transportation expense — Depletion, depreciation and amortization — Impairment of oil and gas properties — — — — — Accretion of asset retirement obligations — General and administrative, net of amounts capitalized Total expenses Income from operations — FINANCING COSTS AND OTHER: Interest expense, net — — Amortization of deferred loan costs — — — Loss (gain) on extinguishment of debt — — — Commodity derivative losses (gains), net — — — Total financing costs and other — — Equity in subsidiary income — — — Income (loss) before income taxes Income tax provision (benefit) — — Net income (loss) $ $ $ $ $ CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS YEAR ENDED DECEMBER 31, 2014 (in thousands) Guarantor Non- ‑Guarantor ‑ Venoco, Inc. Subsidiaries Subsidiary Eliminations Consolidated REVENUES: Oil and natural gas sales $ $ $ — $ — $ Other — Total revenues EXPENSES: Lease operating expense — Production and property taxes — Transportation expense — Depletion, depreciation and amortization — Ceiling test and other impairments — — — Accretion of asset retirement obligations — General and administrative, net of amounts capitalized Total expenses Income from operations — FINANCING COSTS AND OTHER: Interest expense, net — — Amortization of deferred loan costs — — — Loss (gain) on extinguishment of debt — — — Commodity derivative losses (gains), net — — — Total financing costs and other — — Equity in subsidiary income — — — Income (loss) before income taxes Income tax provision (benefit) — — Net income (loss) $ $ $ $ $ CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS YEAR ENDED DECEMBER 31, 2015 (in thousands) Guarantor Non- ‑Guarantor Venoco, Inc. Subsidiaries Subsidiary Eliminations Consolidated REVENUES: Oil and natural gas sales $ $ $ — $ — $ Other — Total revenues EXPENSES: Lease operating expense — Production and property taxes — Transportation expense — Depletion, depreciation and amortization — Ceiling test and other impairments — — — Accretion of asset retirement obligations — General and administrative, net of amounts capitalized Total expenses Income (loss) from operations (1) FINANCING COSTS AND OTHER: Interest expense, net — — Amortization of deferred loan costs — — — Loss (gain) on extinguishment of debt — — — Commodity derivative losses (gains), net — — — Total financing costs and other — — Equity in subsidiary income — — — Income (loss) before income taxes Income tax provision (benefit) — — Net income (loss) $ $ $ $ $ CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2013 (in thousands) Non- Guarantor Guarantor Venoco, Inc. Subsidiaries Subsidiary Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ $ $ $ — $ CASH FLOWS FROM INVESTING ACTIVITIES: Expenditures for oil and natural gas properties — Acquisitions of oil and natural gas properties — — — Expenditures for property and equipment and other — — — Proceeds from sale of oil and natural gas properties — — — Net cash provided by (used in) investing activities — CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from (repayments of) intercompany borrowings — — Proceeds from long-term debt — — — Principal payments on long-term debt — — — Payments for deferred loan costs — — — Premium to retire debt — — — Going private share repurchase costs — — — Dividend paid to Denver Parent Corporation — — — Denver Parent Corporation capital contribution — — — Net cash provided by (used in) financing activities — Net increase (decrease) in cash and cash equivalents — — — Cash and cash equivalents, beginning of period — — — Cash and cash equivalents, end of period $ $ — $ — $ — $ CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2014 (in thousands) Non- Guarantor Guarantor Venoco, Inc. Subsidiaries Subsidiary Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ $ $ $ — $ CASH FLOWS FROM INVESTING ACTIVITIES: Expenditures for oil and natural gas properties — Acquisitions of oil and natural gas properties — — — Expenditures for property and equipment and other — — — Proceeds from sale of oil and natural gas properties — — — Net cash provided by (used in) investing activities — CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from (repayments of) intercompany borrowings — — Proceeds from long-term debt — — — Principal payments on long-term debt — — — Payments for deferred loan costs — — — Dividend paid to Denver Parent Corporation — — — Net cash provided by (used in) financing activities — Net increase (decrease) in cash and cash equivalents — — — Cash and cash equivalents, beginning of period — — — Cash and cash equivalents, end of period $ $ — $ — $ — $ CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2015 (in thousands) Non- Guarantor Guarantor Venoco, Inc. Subsidiaries Subsidiary Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ $ $ $ — $ CASH FLOWS FROM INVESTING ACTIVITIES: Expenditures for oil and natural gas properties — Acquisitions of oil and natural gas properties — — — Expenditures for property and equipment and other — — — Proceeds from sale of oil and natural gas properties — — — Net cash provided by (used in) investing activities — CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from (repayments of) intercompany borrowings — — Proceeds from long-term debt — — — Principal payments on long-term debt — — — Payments for deferred loan costs — — — — — Debt Issuance Costs — — — Increased in restricted cash — — — Net cash provided by (used in) financing activities — Net increase (decrease) in cash and cash equivalents — — — Cash and cash equivalents, beginning of period — — — Cash and cash equivalents, end of period $ $ — $ — $ — $

ORGANIZATION AND SUMMARY OF S22

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2015
ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Operations	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. The consolidated financial statements for Venoco and its consolidated subsidiaries are presented on a separate, stand ‑alone company basis. DPC has engaged in no transactions other than the going private transaction and certain debt transactions, and has incurred no expenses other than interest expenses, deferred loan costs and nominal general and administrative expenses. There are no intercompany sales or expenses between DPC and Venoco. This Annual Report on Form 10 ‑K 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. Principles of Consolidation The consolidated financial statements for DPC include the accounts of DPC and its subsidiaries, all of which are wholly owned. The consolidated financial statements for Venoco include the accounts of Venoco and its subsidiaries, all of which are wholly owned. All intercompany balances and transactions have been eliminated in consolidation.
Basis of Presentation	Chapter 11 Proceedings . On March 18, 2016, the Company filed the Chapter 11 cases in the Bankruptcy Court. Debtor-In-Possession . The Company is currently operating the business as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court has granted all of the first day motions filed by the Company that were designed primarily to minimize the impact of the Chapter 11 proceedings on the Company’s operations, customers and employees. As a result, the Company is not only able to conduct normal business activities and pay all associated obligations for the period following its bankruptcy filing, but it is also authorized to pay and has paid (subject to caps applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and vendors providing services and supplies to lease operations , pre-petition amounts owed to pipeline owners that transport the Company’s production, and funds belonging to third parties, including royalty holders and partners. During the pendency of the Chapter 11 case, all transactions outside the ordinary course of our business require the prior approval of the Bankruptcy Court. Automatic Stay . Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Company and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Restructuring Support Agreement . Immediately prior to the Chapter 11 filings, holders of 100% of the Company’s senior secured notes agreed, pursuant to a restructuring support agreement (the “RSA”), to support a plan under which all of the Company’s senior secured notes will be converted to equity. Following the Chapter 11 filings, the Debtors and their pre-petition secured noteholders continued their efforts to reach a consensual deal with holders of Venoco’s unsecured notes. On March 21, 2016, a majority of Venoco’s unsecured noteholders reached an agreement with the Debtors and pre-petition secured noteholders to join the RSA and support the Plan. On April 8, 2016, the Debtors and the other parties to the original RSA agreed to an amended and restated RSA, which provides for a comprehensive financial restructuring of the Debtors’ capital structure under a confirmable chapter 11 plan of reorganization. On April 20, 2016, the Bankruptcy Court approved the Debtors’ assumption of the amended and restated RSA. The other key terms of the restructuring, as contemplated in the RSA, as amended and restated, are as follows: · General Commitments : The RSA commits each of the Restructuring Support Parties to support, and take all reasonable actions necessary to (A) vote all of its claims against the Debtors to accept the Plan in accordance with the applicable procedures (B) timely return a duly-executed ballot in connection therewith; and (C) not “opt out” of any releases under the Plan. In addition, each of the Restructuring Support Parties agrees to support the Plan and not object to the Plan or corresponding disclosure statement. · Milestones : The RSA sets forth the following milestones, the failure of which may result in the termination of the RSA: § Within 45 days of the Petition Date of March 18, 2016 , the Bankruptcy Court must enter a final order approving the DIP Facility (this milestone was satisified on March 22, 2016); § Within 60 days of the Petition Date , the Bankruptcy Court must enter an order approving the RSA (this milestone was satisified on April 20, 2016); § Within 90 days of the Petition Date , the Bankruptcy Court must enter an order approving the Disclosure Statement (this milestone was satisified on May 16, 2016); § Within 150 days of the Petition Date , the Bankruptcy Court must enter an order confirming the Plan ; and § Within 21 days following the date of the order confirming the Plan , the effective date of the Plan must have occurred. The Debtors may extend a milestone with the express prior written consent of a specified percentage of the noteholders . · Commitment of the Debtors : So long as the RSA has not been terminated, each of the Debtors agrees, among other things, to support and take all necessary actions to consummate the Plan in accordance with the terms of the RSA and the milestones contained in the RSA. · Termination Events : The RSA sets forth a number of customary termination events, which, if they occur, could cause the RSA to terminate, including a failure to meet any of the Milestones discussed above. Plan of Reorganization . On April 11, 2016, the Company filed the Plan with the Bankruptcy Court which is supported by the parties to the amended and restated RSA, and a related disclosure statement. The Plan is subject to approval by the Bankruptcy Court. A confirmation hearing on the Plan is scheduled on July 13, 2016 in the Bankruptcy Court. If the Plan is ultimately approved by the Bankruptcy Court, the Company would exit bankruptcy pursuant to the terms of the Plan. Under the Plan, the holders of the Company’s senior secured notes and certain other unsecured creditors, together with the lenders under the debtor-in-possession credit agreement, are to receive 100% of the new common stock to be issued upon emergence of the Company and the Chapter 11 Subsidiaries from bankruptcy, subject to dilution by any shares issuable upon exercise of new warrants to be issued under the Plan. The Plan is subject to acceptance by certain holders of claims against the Company and confirmation by the Bankruptcy Court. The Plan is deemed accepted by a class of claims entitled to vote if at least one-half in number and two-thirds in dollar amount of claims actually voting in the class has voted to accept the Plan. Under certain circumstances set forth in the Bankruptcy Code, the Bankruptcy Court may confirm a plan even if such plan has not been accepted by all impaired classes of claims and equity interests. In particular, a plan may be compelled on a rejecting class if the proponent of the plan demonstrates that (1) no class junior to the rejecting class is receiving or retaining property under the plan and (2) no class of claims or interests senior to the rejecting class is being paid more than in full. Executory Contracts . Subject to certain exceptions, under the Bankruptcy Code the Company may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Company of performing their future obligations under such executory contract or unexpired lease but may give rise to a pre-petition general unsecured claim for damages caused by such deemed breach. Chapter 11 Filing Impact on Creditors and Stockholders . Under the priority requirements established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities to creditors and post-petition liabilities must be satisfied in full before the holders of our existing common stock are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or stockholders, if any, will not be determined until confirmation and implementation of a plan or plans of reorganization. The outcome of the Chapter 11 case remains uncertain at this time and, as a result, we cannot accurately estimate the amounts or value of distributions that creditors and stockholders may receive. It is possible that stockholders will receive no distribution on account of their interests. Debtor-In-Possession Financing . In connection with the Chapter 11 Cases, on March 18, 2016 the Debtors filed a motion seeking Court approval of debtor in possession financing on the terms set forth in a contemplated Superpriority Secured Debtor-in-Possession Credit Agreement (the “ DIP Facility ”). On March 22, 2016, the Debtors (other than Ellwood Pipeline, Inc.) entered into the DIP Facility with certain of the holders of the Company's pre-petition first lien notes, and Wilmington Trust, National Association, as administrative agent (the “Administrative Agent”). The DIP Facility provides for a senior secured superpriority non-amortizing delayed draw term loan facility in an aggregate principal amount of up to $35.0 million. The key terms of the DIP Facility are as follows: · Availability : After entry of the final order approving the DIP Facility, the Company may borrow (a) amounts not exceeding $10.0 million per borrowing, (b) no more t h a n four times during the t e r m of the D I P F ac i l i t y , and ( c ) until t h e California State Lands Commission has approved the LLA, not more than $20.0 million . · DIP Financing Termination Date: The DIP Facility shall terminate on the earliest date to occur of (a) December 31, 2016, (b) 45 days after March 18, 2016 if the Bankruptcy Court has not entered a final order approving the DIP Facility, (c) the substantial consummation of the Plan, (d) the date on which all commitments under the DIP Facility have terminated and all obligations under the DIP Facility have been paid in full in cash and (e) the date on which the commitments under the DIP Facility have been terminated or all or any portion of the loans have been accelerated in accordance with the DIP Facility (such earliest date to occur of the foregoing clauses (a) through (e), the “ DIP Financing Termination Date ”). · Interest Rate : Term Loans will bear interest, at the option of the Company, at (i) 9% plus the Administrative Agent’s base rate, payable monthly in arrears or (ii) 10% plus the current LIBO Rate as quoted by the Administrative Agent for interest periods of one , two , three or six months (the “ LIBO Rate ”), payable at the end of the relevant interest period, but in any event at least quarterly; provided that the Base Rate shall not be less than 2% and the LIBO Rate shall be not less than 1% per annum. · Fees : The fees for the DIP Facility are as follows: § Upfront Fee : For the account of the Lenders, an upfront fee equal to 1.00% of the lenders’ commitment. § Ticking Fee : An unused commitment fee at the rate of 1.00% per annum on the undrawn portion of the DIP Facility. § Backstop Fee : A backstop fee equal to (i) 10% of the common equity of the post-emergence Company issued and outstanding as of the effective date of the Plan, to be due and payable on effectiveness of the Plan, or (ii) in the event the RSA is terminated without the Plan having been consummated, 5.00% of the aggregate principal amount of loans that have been funded, to be due and payable in cash on the later to occur of the (x) the DIP Financing Termination Date and (y) the date of termination of the RSA. · Events of Default : The DIP Facility contains events of default, such as non-payment of required principal and interest, breach of its obligations under the restructuring agreement or change of control. · Budget : On or before the last day of every other calendar week, the Company shall not permit the aggregate amounts (i) for each of certain cash flow forecast line items actually made by the Loan Parties (as defined under the credit agreement for the DIP Facility) in the cash flow forecast during the six -week period ending on the Friday before such day (each such date, a “ Test Date ”) to exceed, on a cumulative basis, the aggregate budgeted amounts set forth in the cash flow forecast in effect for such applicable six -week period for such line item by more than 20% , and (ii) for the aggregate amount of those expenditures in the cash flow forecast actually made by the Loan Parties during the six -week period ending on the Test Date to exceed, on a cumulative basis, the aggregate budgeted amounts set forth in the cash flow forecast in effect for such six -week period for the such items by more than 15% . · Case Milestones : The DIP Facility requires compliance with the following milestones in accordance with the applicable timing (or such later dates as approved by the lenders under the DIP Facility): (a) no later than October 15, 2016, the Bankruptcy Court shall have entered the order for the Plan disclosure statement; (b) no later than December 1, 2016, the Bankruptcy Court shall have entered the order confirming the Plan; and (c) no later than 14 days following the entry of the order confirming the Plan, the Plan shall become effective. Reorganization Expenses . The Company and the Chapter 11 Subsidiaries will incur significant costs associated with the reorganization, principally professional fees. The costs will be expensed as incurred, and are expected to significantly affect our results of operations. In accordance with ASC 852, we will record certain costs associated with the bankruptcy proceedings as Reorganization Items within our Consolidated Statement of Operations. For additional information, see “Reorganization Items” below. Risks Associated with Chapter 11 Proceedings . For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process as described in Item 1A, “Risk Factors.” Because of these risks and uncertainties, the description of our operations, properties and capital plans included in this report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.
Principles of Consolidation	Principles of Consolidation The consolidated financial statements for DPC include the accounts of DPC and its subsidiaries, all of which are wholly owned. The consolidated financial statements for Venoco include the accounts of Venoco and its subsidiaries, all of which are wholly owned. All intercompany balances and transactions have been eliminated in consolidation.
Use of Estimates	Use of Estimates 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. The Company has evaluated subsequent events and transactions for matters that may require recognition or disclosure in these financial statements.
Business Segment Information	Business Segment Information The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, natural gas and natural gas liquids. The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of the Company’s operations and assets are located in the United States, and all of its revenues are attributable to United States customers.
Revenue Recognition and Gas Imbalances	Revenue Recognition and Gas Imbalances Revenues from the sale of natural gas and crude oil are recognized when the product is delivered at a fixed or determinable price, title has transferred, collectability is reasonably assured and evidenced by a contract. This generally occurs when oil or natural gas has been delivered to a refinery or a pipeline, or has otherwise been transferred to a customer’s facilities or possession. The Company uses the entitlement method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual production of natural gas. The Company incurs production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under ‑deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over ‑ and under ‑ deliveries or by cash settlement, as required by applicable contracts. The Company’s production imbalances were not material at December 31, 2014 and 2015. Other revenues primarily include pipeline revenues and other miscellaneous revenues.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents consist of cash and liquid investments with an original maturity of three months or less.
Restricted Cash	Restricted Cash 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.
Accounts Receivable	Accounts Receivable The components of accounts receivable include the following (in thousands): December 31, 2014 2015 Venoco and DPC: Oil and natural gas sales related $ $ Joint interest billings related Realized gains on derivatives Other Allowance for doubtful accounts Venoco total accounts receivable, net $ $ The Company’s accounts receivable result primarily from (i) oil and natural gas sales to large oil refining companies and independent marketers and (ii) billings to joint working interest partners in properties operated by the Company. The Company’s trade and accrued production receivables are spread among limited number of customers and purchasers and most of the Company’s significant purchasers are large companies with solid credit ratings. If customers are considered a credit risk, letters of credit are the primary security obtained to support the extension of credit. For most joint working interest partners, the Company may have the right of offset against related oil and natural gas revenues. As of December 31, 2015, 97% of the oil and natural gas sales related accounts receivable balance was receivable from the Company’s two major customers. The following table provides the percentage of revenue derived from oil and natural gas sales to customers who comprise 10% or more of the Company’s annual revenue (the customers in each year are not necessarily the same from year to year): Years Ended December 31, 2013 2014 2015 Tesoro Refining and Marketing Company % % % ConocoPhillips 66 % % %
Accounts Receivable - Insurance	Insurance Receivable O n March 16, 2016 the Company reached a settlement in the Delaware Litigation, which is further discussed in footnote 12, whereby Venoco and/or the insurers will pay $19 million to be distributed to the class. As part of the settlement the insurance companies have signed the Insurance Settlement which states that they will pay $16.5 million of the $19 million Litigation Settlement amount. As a result of the Litigation Settlement, $19 million was recorded in the balance sheet within Accounts Payable and Accrued Liabilities, with $16.5 million recorded as a receivable, as it is an insurance recovery to be received pursuant to the Insurance Settlement. The portion that the Company will ultimately owe is $2.5 million which is recorded in the statement of operations within General and Administrative Expenses.
Inventories	Inventories Included in inventories are oil field materials and supplies, stated at the lower of cost or market, cost being determined by the first ‑ in, first ‑out method.
Oil and Natural Gas Properties	Oil and Natural Gas Properties The Company’s oil and natural gas producing activities are accounted for using the full cost method of accounting. Accordingly, the Company capitalizes all costs incurred in connection with the acquisition of oil and natural gas properties and with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as adjustments to the full cost pool, with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. Depletion of the capitalized costs of oil and natural gas properties, including estimated future development and abandonment costs, is provided for using the equivalent unit ‑of ‑production method based upon estimates of proved oil and natural gas reserves. Depletion expense for the years ended December 31, 2013, 2014 and 2015 was $46.0 million, $42.0 million and $22.0 million, respectively. Unproved property costs not subject to amortization consist primarily of leasehold and seismic costs related to unproved areas. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. The Company transferred $4.0 million and $8.6 million of unproved costs into the amortization base in 2013 and 2015, respectively, due to impairment, development of acreage or placement of assets into service. No interest costs were capitalized in 2013, 2014 or 2015 because the Company did not have any unusually significant investments in unproved properties that qualify for interest capitalization. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are subject to a ceiling based upon the related estimated future net revenues, discounted at 10 percent, net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. The Company did not record an impairment of oil and natural gas properties in 2013. In 2014, the Company recorded $0.8 million impairment of a prospect in Argentina. In 2015 the Company recorded a $437.5 million impairment due to ceiling test limitations. The impairment was primarily due 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 could 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 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.
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities The components of accounts payable and accrued liabilities include the following. December 31, 2014 2015 Venoco and DPC: Accounts Payable $ $ Accrued Liabilities Accrued Liabilities - Delaware Settlement — Accrued Payroll and Bonus Accrued Taxes Notes payable Revenue and Severance tax payable Other
General and Administrative Expenses	December 31, 2014 2015 Venoco and DPC: Accounts Payable $ $ Accrued Liabilities Accrued Liabilities - Delaware Settlement — Accrued Payroll and Bonus Accrued Taxes Notes payable Revenue and Severance tax payable Other General and Administrative Expenses Under the full cost method of accounting, the Company capitalizes a portion of general and administrative expenses that are directly identified with exploration, exploitation and development activities. These capitalized costs include salaries, employee benefits, costs of consulting services and other specifically identifiable costs and do not include costs related to production operations, general corporate overhead or similar activities. The Company capitalized general and administrative costs of $ 23.0 million, $8.7 million and $ 9.0 million directly related to its exploration, exploitation and development activities during 2013, 2014 and 2015, respectively.
Other Property and Equipment	Other Property and Equipment Other property and equipment, which includes land, drilling equipment, leasehold improvements, office and other equipment, are stated at cost. Depreciation and amortization are calculated using the straight ‑line method over the estimated useful lives of the related assets, ranging from 3 to 25 years. Depreciation and amortization expense for the years ended December 31, 2013, 2014 and 2015 was $2.8 million, $2. 1 million and $1.6 million, respectively.
Derivative Financial Instruments	Derivative Financial Instruments From time to time the Company enters into derivative contracts, primarily collars, swaps and option contracts, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivative instruments are recorded on the balance sheet at fair value. The Company has elected not to apply hedge accounting to any of its derivative transactions and, consequently, the Company recognizes mark ‑to ‑market gains and losses in earnings currently, rather than deferring such amounts in other comprehensive income for those commodity derivatives that qualify as cash flow hedges.
Deferred Loan Costs	Deferred Loan Costs In 2015 the Company changed the manner in which it reports debt issuance costs due to adoption of ASU No. 2015-03, “Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” (“ASU 2015-03”). Debt issuance costs related to a recognized debt liability previously reported as assets have been reclassified as a direct deduction from the carrying amount of debt liabilities in the Company’s consolidated financial statements in all periods presented. The effects of the standard were applied retrospectively to all prior interim and annual periods within this annual report. The effect of the change in accounting principle as of December 31, 2015 and December 31, 2014 , was that $10.6 million and $7.1 million, respectively, of Venoco’s deferred loan costs have been reclassified from other assets to debt on the Company’s consolidated financial statements. Additionally, as of December 31, 2015 and December 31, 2014 $13.6 million and $11.6 million, respectively, of deferred loan costs have been reclassifed for DPC.
Asset Retirement Obligations	Asset Retirement Obligations The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and natural gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long ‑lived asset are recorded at the time the well is spud or acquired.
Environmental	Environmental The Company is subject to extensive federal, state and local environmental laws and regulations. These laws and regulations, which regularly change, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non ‑capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally recorded at their undiscounted amounts unless the amount and timing of payments is fixed or reliably determinable. The Company believes that it is in material compliance with existing laws and regulations.
Other Employee Benefit Plans	Other Employee Benefit Plans The Company sponsors a 401(k) tax deferred savings plan (the 401(k) Plan) and makes it available to employees. The 401(k)Plan is a defined contribution plan, and the Company may make discretionary matching contributions of up to 90% of their annual compensation, not to exceed contribution limits established by the Internal Revenue Code. The Company makes matching contributions of 100% of participant contributions on the first 5% of compensation and 50% of participant contribution thereafter. The contributions made by the Company totaled approximately $2.0 million, $ 1.7 million and $1.3 million during the years ended December 31, 2013, 2014, and 2015, respectively.
Share-Based Compensation	Share ‑Based Compensation Share ‑based compensation for equity awards is measured at the estimated grant date fair value of the awards and is recognized over the requisite service period (usually the vesting period). The Company estimates forfeitures in calculating the cost related to share ‑based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur. Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered. A market condition is not considered to be a vesting condition with respect to compensation expense. Therefore, an award is not deemed to be forfeited solely because a market condition is not satisfied. The Company measures its liability awards based on the award’s fair value remeasured at each reporting date until the date of settlement. Compensation cost for each period until settlement is based on the change (or a portion of the change, depending on the percentage of the requisite service that has been rendered at the reporting date). Changes in the fair value of a liability that occur after the end of the requisite service period are compensation cost of the period in which the changes occur. Any difference between the amount for which a liability award is settled and its fair value at the settlement date is an adjustment of compensation cost in the period of settlement.
Income Taxes	Income Taxes In 2015, the Company changed the manner in which it reports deferred taxes due to electing early adoptions of ASU No. 2015-17, “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes” (“ASU 2015-17”). Deferred tax liabilities and assets are now all reported as non-current amounts. Because the application of this guidance affects the classification only, such reclassifications did not have a material effect on the Company’s consolidated financial position or results of operations. Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not 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. 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. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The Company’s policy is to recognize interest and/or penalties related to uncertain tax positions in interest expense.
Consolidated Statements of Comprehensive Income (Loss)	Consolidated Statements of Comprehensive Income (Loss) No statement is presented because the Company had no comprehensive income or loss activity during the years ended December 31, 2013, 2014, or 2015.
Recently Issued Accounting Standards	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, 2016, 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 does not expect this standard to have a material impact on the Company’s financial statements upon adoption

ORGANIZATION AND SUMMARY OF S23

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2015
ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Schedule of components of accounts receivable	December 31, 2014 2015 Venoco and DPC: Oil and natural gas sales related $ $ Joint interest billings related Realized gains on derivatives Other Allowance for doubtful accounts Venoco total accounts receivable, net $ $
Schedule of percentage of revenue derived from oil and natural gas sales to customers who comprise 10% or more of the Company's annual revenue	Years Ended December 31, 2013 2014 2015 Tesoro Refining and Marketing Company % % % ConocoPhillips 66 % % %
Schedule of accounts payable and accrued liabilities	December 31, 2014 2015 Venoco and DPC: Accounts Payable $ $ Accrued Liabilities Accrued Liabilities - Delaware Settlement — Accrued Payroll and Bonus Accrued Taxes Notes payable Revenue and Severance tax payable Other

DEBT (Tables)

DEBT (Tables)	12 Months Ended
	Dec. 31, 2015
DEBT
Schedule of debt	As of the dates indicated, the Company’s debt consisted of the following (in thousands): Venoco, Inc. Denver Parent Corporation December 31, December 31, December 31, December 31, 2014 2015 2014 2015 Venoco revolving credit agreement due March 2016 $ $ — $ $ — Venoco 8.875% senior notes due February 2019 First lien secured 12% notes due February 2019 — — Second lien secured 8.875% / 12% PIK notes due February 2019(1) — — Term loan facility due December 2017(2) — — DPC 12.25% / 13.00% senior PIK toggle notes due August 2018(3) — — Deferred Loan Costs Total long-term debt Less: current portion of long-term debt — — Long-term debt, net of current portion $ $ — $ $ —
Scheduled of annual maturities of debt outstanding	Scheduled annual maturities of debt outstanding as of December 31, 2015 were as follows (in thousands): Denver Parent Year Ending December 31, (in thousands): Venoco, Inc. Corporation 2016 $ — $ — 2017 2018 — 2019 2020 — — Thereafter — — $ $

HEDGING AND DERIVATIVE FINANC25

HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
Schedule of oil derivatives	Oil (Brent) Weighted Avg. Barrels/day Prices per Bbl January 1 - December 31, 2016: Swaps $
Schedule of estimated fair values of derivatives included in the condensed consolidated balance sheets	The main headings represent the balance sheet captions for the contracts presented (in thousands). December 31, December 31, 2014 2015 Current Assets—Commodity derivatives: Oil derivative contracts $ $ Noncurrent Assets—Commodity derivatives: Oil derivative contracts — Net derivative asset $ $
Commodity derivatives
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
Schedule of components of derivative losses (gains) in the condensed consolidated statements of operations	The components of commodity derivative losses (gains) in the consolidated statements of operations are as follows (in thousands): 2013 2014 2015 Realized commodity derivative losses (gains) $ $ $ Unrealized commodity derivative losses (gains) for changes in fair value Commodity derivative losses (gains), net $ $ $

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2015
ASSET RETIREMENT OBLIGATIONS
Schedule of the activities for the Company's asset retirement obligations	The following table summarizes the activities for the Company’s asset retirement obligations for the years ended December 31, 2014 and 2015 (in thousands): 2014 2015 Asset retirement obligations at beginning of period $ $ Revisions of estimated liabilities Liabilities incurred or acquired — Liabilities settled or disposed Accretion expense Asset retirement obligations at end of period Less: current asset retirement obligations (classified with accounts payable and accrued liabilities) Long-term asset retirement obligations $ $

SHARE-BASED PAYMENTS (Tables)

SHARE-BASED PAYMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
SHARE-BASED PAYMENTS
Summary of cash settlement awards activity	Share Employee Stock Restricted Share Units Appreciation Rights Aggregate Ownership Plan Weighted Weighted Intrinsic Weighted Rights to Receive Average Average Value of Average Cash Grant-Date Grant-Date SARs Grant-Date Units Value Units Fair Value Units Fair Value Exercisable Units Fair Value Outstanding, end of period, December 31, 2013 Granted — — Vested or exercised — — Cancelled and other Exercisable, end of period — — $ — — Outstanding, end of period, December 31, 2014 $ $ $ $ Vested or exercised — Cancelled and other Exercisable, end of period — — $ — — Outstanding, end of period, December 31, 2015
Schedule of additional information related to SARs outstanding	Additional information related to SARs outstanding at December 31, 2015 is as follows: SARs Outstanding SARs Exercisable Weighted Weighted Average Weighted- Average Weighted Remaining Average Remaining Average Number Contractual Exercise Number Contractual Exercise Range of Exercise Prices Outstanding Life Prices Exercisable Life Prices $ 8.33 $ $ $ 12.24 $ $ $ 12.50 $ $ $ - $ 20.00 $ $ $ $
Schedule of assumptions used to compute the grant date fair value of SARS	December 31, 2014 Expected lives - years Risk free interest rates % - % Estimated volatilities % - % Dividend yield %
Schedule of share-based compensation liability	The following table summarizes Company’s share ‑based compensation liability at (in thousands): December 31, December 31, 2014 2015 Share-based compensation liability at beginning of period $ $ Total share-based compensation costs (income) Payouts APIC adjustment Share-based compensation liability at end of period Less: current share-based compensation liability Long-term share-based compensation liability $ $
Summary of composition of share-based compensation liability	The following summarizes the composition of the share ‑based compensation liability at (in thousands): December 31, 2014 December 31, 2015 Current Long Term Total Current Long Term Total Liability Liability Liability Liability Liability Liability Rights to receive $ $ — $ $ $ — $ Restricted share units — — Share appreciation rights — — — — ESOP — — Total share-based compensation liability $ $ $ $ $ $
Schedule of recognized total share-based compensation costs	The Company recognized total share ‑based compensation costs as follows (in thousands): Years Ended December 31, 2013 2014 2015 General and administrative expense (income) $ $ $ Oil and natural gas production expense (income) Total share-based compensation costs (income) Less: share-based compensation costs capitalized (reduced) Share-based compensation expense (income) $ $ $

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
FAIR VALUE MEASUREMENTS
Schedule of financial assets and liabilities accounted for at fair value	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 December 31, 2015 (in thousands). Fair Value as of December 31, Level 1 Level 2 Level 3 2015 Assets (Liabilities): Commodity derivative contracts $ — $ $ — $ Share-based compensation — —
Summary of changes in fair value of financial assets (liabilities), which represent primarily share-based compensation liabilities, designated as Level 3 in the valuation hierarchy	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): Year Ended December 31, 2014 2015 Fair value liability, beginning of period $ $ Transfers into Level 3(1) Transfers out of Level 3(2) Change in fair value of Level 3 Fair value liability, end of period $ $ (1) The transfers into Level 3 liability during 2014 and 2015 relate to RSU, SAR and ESOP requisite service period expense. (2) The transfers out of Level 3 liability during 2015 relate to cash settlements of RSU grants, and forfeitures of RSU, SAR and ESOP grants as a result of employee terminations.
Schedule of 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 data and valuation techniques (Level 2) to estimate the fair value of the first lien and second lien notes. This disclosure does not impact our financial position, results of operations or cash flows (in thousands) . December 31, 2014 December 31, 2015 Carrying Estimated Carrying Estimated Value Fair Value Value Fair Value Venoco: Revolving credit agreement $ $ $ — $ — Venoco 8.875% senior notes due February 2019 First lien secured 12% notes due February 2019 — — Second lien secured 8.875% / 12% PIK notes due February 2019 (1) — — Term loan facility due December 2017 — — Denver Parent Corporation: 12.25% / 13.00% senior PIK toggle notes (2) (1) Amounts include $9.3 million of accrued PIK interest not yet capitalized. Amounts include $14.8 million of accrued PIK interest not yet capitalized

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2015
INCOME TAXES
Schedule of reconciliation of the income tax provision (benefit) computed by applying the federal statutory rate to the Company's income tax provision (benefit)	A reconciliation of the income tax provision (benefit) computed by applying the federal statutory rate of 35% to the Company’s income tax provision (benefit) is as follows (in thousands): Venoco, Inc. Denver Parent Corporation Years Ended December 31, Years Ended December 31, 2013 2014 2015 2013 2014 2015 Income tax expense (benefit) at federal statutory rate $ $ $ $ $ $ State income tax expense (benefit) Other Valuation allowance $ — $ — $ — $ — $ — $ —
Schedule of components of deferred tax assets and (liabilities)	The components of deferred tax assets and (liabilities) are as follows (in thousands): Venoco, Inc. Denver Parent Corporation December 31, December 31, December 31, December 31, 2014 2015 2014 2015 Deferred income tax assets: Net operating losses $ $ $ $ Oil and gas properties — — Accrued liabilities Share-based compensation Charitable contributions Other current assets Asset retirement obligations Alternative minimum tax credits Valuation allowance Deferred income tax liabilities: Oil and gas properties — — Unrealized commodity derivative gains Prepaid expenses Investments Net deferred income tax assets (liabilities) $ — $ — $ — $ —

QUARTERLY FINANCIAL DATA (UNA30

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2015
QUARTERLY FINANCIAL DATA (UNAUDITED)
Summary of the unaudited financial data for each quarter	The following is a summary of the unaudited financial data for each quarter for the years ended December 31, 2014 and 2015 (in thousands): Venoco, Inc. Denver Parent Corporation Three Months Ended Three Months Ended March 31, June 30, September 30, December 31, March 31, June 30, September 30, December 31, 2014 2014 2014 2014 2014 2014 2014 2014 Year Ended December 31, 2014 Revenues $ $ $ $ $ $ $ $ Income (loss) from operations Net income (loss) Venoco, Inc. Denver Parent Corporation Three Months Ended Three Months Ended March 31, June 30, September 30, December 31, March 31, June 30, September 30, December 31, 2015 2015 2015 2015 2015 2015 2015 2015 Year Ended December 31, 2015 Revenues $ $ $ $ $ $ $ $ Income (loss) from operations Net income (loss)

SUPPLEMENTAL INFORMATION ON O31

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2015
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
Schedule of capitalized costs of oil and natural gas properties	As of December 31, 2013 2014 2015 (in thousands) Unevaluated properties $ $ $ — Properties subject to amortization Total capitalized costs Accumulated depletion(1) Net capitalized costs $ $ $ (1) Depletion expense for the years ended December 31, 2013, 2014 and 2015 was $46.0 million, $42.0 million and $22.0 million, respectively ( $13.2 7 , $15.54 and $15.15 , respectively, per equivalent barrel of oil).
Schedule of costs incurred for oil and natural gas exploration, development and acquisition	Years Ended December 31, 2013 2014 2015 (in thousands) Property acquisition and leasehold costs: Unevaluated property $ $ $ — Proved property Exploration costs Development costs Total costs incurred $ $ $
Schedule of the Company's net proved reserves, including changes, proved developed reserves and proved undeveloped reserves (all within the United States)	Crude Oil, Liquids and Condensate (MBbls)(4) Natural Gas (MMcf) 2013(1) 2014(2) 2015(3) 2013(1) 2014(2) 2015(3) Beginning of the year reserves Revisions of previous estimates Extensions and discoveries(5) — — — Purchases of reserves in place — — — — — — Production Sales of reserves in place — — — — End of year reserves Proved developed reserves: Beginning of year End of year Proved undeveloped reserves: Beginning of year End of year — — (1) Unescalated twelve month arithmetic average of the first day of the month posted prices of $96.78 per Bbl for oil and natural gas liquids and $3.67 per MMBtu for natural gas were adjusted for quality, energy content, transportation fees and regional price differentials to arrive at realized prices of $98.37 per Bbl for oil, $79.04 per Bbl for natural gas liquids and $4.41 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2013. (2) Unescalated twelve month arithmetic average of the first day of the month posted prices of $94.99 per Bbl for oil and natural gas liquids and $4.35 per MMBtu for natural gas were adjusted as in note (1) above to arrive at realized prices of $86.69 per Bbl for oil, $71.12 per Bbl for natural gas liquids and $5.21 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2014. (3) Unescalated twelve month arithmetic average of the first day of the month posted prices of $50.28 per Bbl for oil and natural gas liquids and $2.58 per MMBtu for natural gas were adjusted as in note (1) above to arrive at realized prices of $38. 32 per Bbl for oil, $32.28 per Bbl for natural gas liquids and $2.96 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2015. (4) Natural gas liquids reserves represent a minimal percentage of our total reserves (approximately 3.4% , 3.8% and 5.8% at December 31, 2013, 2014 and 2015, respectively), therefore natural gas liquids are not presented separately but rather are included with oil volumes. (5) Extensions for the year ended December 31, 2013 represent results from the drilling at the South Ellwood field of the Coal Oil Point well and the addition of reserves for two additional undeveloped locations. Extensions for the year ended December 31, 2014 represent results from the drilling of a M2 infill well at Sockeye.
Schedule of standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	As of December 31, 2013 2014 2015 (in thousands) Future cash inflows $ $ $ Future production costs Future development and abandonment costs Future income taxes — Future net cash flows 10% annual discount for estimated timing of cash flows Standardized measure of discounted future net cash flows $ $ $
Summary of changes in the standardized measure of discounted future net cash flows	Years Ended December 31, 2013 2014 2015 (in thousands) Beginning of the year $ $ $ Changes in prices and production costs Revisions of previous quantity estimates Changes in future development costs Development costs incurred during the period Extensions, discoveries and improved recovery, net of related costs — Sales of oil and natural gas, net of production costs Accretion of discount Net change in income taxes Sale of reserves in place — — Purchases of reserves in place — — — Production timing and other End of year $ $ $

GUARANTOR FINANCIAL INFORMATI32

GUARANTOR FINANCIAL INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2015
GUARANTOR FINANCIAL INFORMATION
Schedule of condensed consolidating balance sheets	CONDENSED CONSOLIDATING BALANCE SHEETS AT DECEMBER 31, 2014 (in thousands) Non- Guarantor Guarantor Venoco, Inc. Subsidiaries Subsidiary Eliminations Consolidated ASSETS CURRENT ASSETS: Cash and cash equivalents $ $ — $ — $ — $ Accounts receivable — Inventories — — — Other current assets — — — Commodity derivatives — — — TOTAL CURRENT ASSETS — PROPERTY, PLANT & EQUIPMENT, NET — COMMODITY DERIVATIVES — — — INVESTMENTS IN AFFILIATES — — — OTHER — — TOTAL ASSETS LIABILITIES AND STOCKHOLDERS’ EQUITY CURRENT LIABILITIES: Accounts payable and accrued liabilities — — — Interest payable — — — Share-based compensation — — — TOTAL CURRENT LIABILITIES: — — — LONG-TERM DEBT — — — COMMODITY DERIVATIVES — — — — — ASSET RETIREMENT OBLIGATIONS — SHARE-BASED COMPENSATION — — — INTERCOMPANY PAYABLES (RECEIVABLES) — TOTAL LIABILITIES TOTAL STOCKHOLDERS’ EQUITY (DEFICIT) TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) $ $ $ $ $ CONDENSED CONSOLIDATING BALANCE SHEETS AT DECEMBER 31, 2015 (in thousands) Non- Guarantor Guarantor Venoco, Inc. Subsidiaries Subsidiary Eliminations Consolidated ASSETS CURRENT ASSETS: Cash and cash equivalents $ $ — $ — $ — $ Restricted funds — — — Accounts receivable — Insurance receivable — — — Inventories — — — Other current assets — — — Commodity derivatives — — — TOTAL CURRENT ASSETS — PROPERTY, PLANT & EQUIPMENT, NET — COMMODITY DERIVATIVES — — — — — INVESTMENTS IN AFFILIATES — — — OTHER — — TOTAL ASSETS LIABILITIES AND STOCKHOLDERS’ EQUITY CURRENT LIABILITIES: Accounts payable and accrued liabilities — — — Interest payable — — — Share-based compensation — — — CURRENT PORTION OF LONG-TERM DEBT — — — TOTAL CURRENT LIABILITIES: — — — COMMODITY DERIVATIVES — — — — — ASSET RETIREMENT OBLIGATIONS — SHARE-BASED COMPENSATION — — — INTERCOMPANY PAYABLES (RECEIVABLES) — TOTAL LIABILITIES TOTAL STOCKHOLDERS’ EQUITY (DEFICIT) TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) $ $ $ $ $
Schedule of condensed consolidating statements of operations	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS AT DECEMBER 31, 2013 (in thousands) Guarantor Non-Guarantor Venoco, Inc. Subsidiaries Subsidiary Eliminations Consolidated REVENUES: Oil and natural gas sales $ $ $ — $ — $ Other — Total revenues EXPENSES: Lease operating expense — Production and property taxes — Transportation expense — Depletion, depreciation and amortization — Impairment of oil and gas properties — — — — — Accretion of asset retirement obligations — General and administrative, net of amounts capitalized Total expenses Income from operations — FINANCING COSTS AND OTHER: Interest expense, net — — Amortization of deferred loan costs — — — Loss (gain) on extinguishment of debt — — — Commodity derivative losses (gains), net — — — Total financing costs and other — — Equity in subsidiary income — — — Income (loss) before income taxes Income tax provision (benefit) — — Net income (loss) $ $ $ $ $ CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS YEAR ENDED DECEMBER 31, 2014 (in thousands) Guarantor Non- ‑Guarantor ‑ Venoco, Inc. Subsidiaries Subsidiary Eliminations Consolidated REVENUES: Oil and natural gas sales $ $ $ — $ — $ Other — Total revenues EXPENSES: Lease operating expense — Production and property taxes — Transportation expense — Depletion, depreciation and amortization — Ceiling test and other impairments — — — Accretion of asset retirement obligations — General and administrative, net of amounts capitalized Total expenses Income from operations — FINANCING COSTS AND OTHER: Interest expense, net — — Amortization of deferred loan costs — — — Loss (gain) on extinguishment of debt — — — Commodity derivative losses (gains), net — — — Total financing costs and other — — Equity in subsidiary income — — — Income (loss) before income taxes Income tax provision (benefit) — — Net income (loss) $ $ $ $ $ CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS YEAR ENDED DECEMBER 31, 2015 (in thousands) Guarantor Non- ‑Guarantor Venoco, Inc. Subsidiaries Subsidiary Eliminations Consolidated REVENUES: Oil and natural gas sales $ $ $ — $ — $ Other — Total revenues EXPENSES: Lease operating expense — Production and property taxes — Transportation expense — Depletion, depreciation and amortization — Ceiling test and other impairments — — — Accretion of asset retirement obligations — General and administrative, net of amounts capitalized Total expenses Income (loss) from operations (1) FINANCING COSTS AND OTHER: Interest expense, net — — Amortization of deferred loan costs — — — Loss (gain) on extinguishment of debt — — — Commodity derivative losses (gains), net — — — Total financing costs and other — — Equity in subsidiary income — — — Income (loss) before income taxes Income tax provision (benefit) — — Net income (loss) $ $ $ $ $
Schedule of condensed consolidating statement of cash flows	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2013 (in thousands) Non- Guarantor Guarantor Venoco, Inc. Subsidiaries Subsidiary Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ $ $ $ — $ CASH FLOWS FROM INVESTING ACTIVITIES: Expenditures for oil and natural gas properties — Acquisitions of oil and natural gas properties — — — Expenditures for property and equipment and other — — — Proceeds from sale of oil and natural gas properties — — — Net cash provided by (used in) investing activities — CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from (repayments of) intercompany borrowings — — Proceeds from long-term debt — — — Principal payments on long-term debt — — — Payments for deferred loan costs — — — Premium to retire debt — — — Going private share repurchase costs — — — Dividend paid to Denver Parent Corporation — — — Denver Parent Corporation capital contribution — — — Net cash provided by (used in) financing activities — Net increase (decrease) in cash and cash equivalents — — — Cash and cash equivalents, beginning of period — — — Cash and cash equivalents, end of period $ $ — $ — $ — $ CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2014 (in thousands) Non- Guarantor Guarantor Venoco, Inc. Subsidiaries Subsidiary Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ $ $ $ — $ CASH FLOWS FROM INVESTING ACTIVITIES: Expenditures for oil and natural gas properties — Acquisitions of oil and natural gas properties — — — Expenditures for property and equipment and other — — — Proceeds from sale of oil and natural gas properties — — — Net cash provided by (used in) investing activities — CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from (repayments of) intercompany borrowings — — Proceeds from long-term debt — — — Principal payments on long-term debt — — — Payments for deferred loan costs — — — Dividend paid to Denver Parent Corporation — — — Net cash provided by (used in) financing activities — Net increase (decrease) in cash and cash equivalents — — — Cash and cash equivalents, beginning of period — — — Cash and cash equivalents, end of period $ $ — $ — $ — $ CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2015 (in thousands) Non- Guarantor Guarantor Venoco, Inc. Subsidiaries Subsidiary Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ $ $ $ — $ CASH FLOWS FROM INVESTING ACTIVITIES: Expenditures for oil and natural gas properties — Acquisitions of oil and natural gas properties — — — Expenditures for property and equipment and other — — — Proceeds from sale of oil and natural gas properties — — — Net cash provided by (used in) investing activities — CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from (repayments of) intercompany borrowings — — Proceeds from long-term debt — — — Principal payments on long-term debt — — — Payments for deferred loan costs — — — — — Debt Issuance Costs — — — Increased in restricted cash — — — Net cash provided by (used in) financing activities — Net increase (decrease) in cash and cash equivalents — — — Cash and cash equivalents, beginning of period — — — Cash and cash equivalents, end of period $ $ — $ — $ — $

ORGANIZATION AND SUMMARY OF S33

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) $ in Millions	Mar. 22, 2016USD ($)item	Dec. 31, 2015	Apr. 16, 2016	Mar. 17, 2016
Chapter 11 Of U S Bankruptcy Code
Plan of Reorganization
Number of days Bankruptcy Court must enter final order approving DIP facility		45 days
Number of days Bankruptcy Court must enter an order approving RSA		60 days
Number of days Bankruptcy Court must enter order approving the filed in connection with the Plan		90 days
Number of days Bankruptcy Court enter order confirming Plan		150 days
Number of days following date of order confirming Plan effective date of plan must occur		21 days
Forecast | Chapter 11 Of U S Bankruptcy Code
Plan of Reorganization
Minimum of votes for deemed acceptance (as a percentage)			50
Minimum claims amount for deemed acceptance (as a percentage)			66.67
Debtor-in-Possession Financing
Debtor-in-Possession Financing, amount currently available	$ 10
Debtor-in-Possession Financing, number of withdrawals permissible | item	4
Debtor-in-Possession Financing, amount currently available without approval	$ 20
Interest payment period	1 month
Interest payment period, second option	2 months
Interest payment period, third option	3 months
Interest payment period, fourth option	6 months
Upfront Fee	1.00%
Ticking Fee	1.00%
Backstop Fee, as a percent of common equity	10.00%
Backstop Fee, as a percent of aggregate principal amount	5.00%
Number of weeks line items must meed DIP Facility budget	42 days
Percentage of cash flow forecast, during six week period ending on Friday	20.00%
Percentage of cash flow forecast, during six week period	15.00%
Days DIP Facility has to become compliant	14 days
Forecast | Base rate | Chapter 11 Of U S Bankruptcy Code
Debtor-in-Possession Financing
Interest rate (as a percent)	9.00%
Stated interest rate (as a percent)	2.00%
Forecast | LIBOR | Chapter 11 Of U S Bankruptcy Code
Plan of Reorganization
Senior notes convertible to equity (as a percentage)				100.00%
Debtor-in-Possession Financing
Interest rate (as a percent)	10.00%
Stated interest rate (as a percent)	1.00%
Maximum | Forecast | Chapter 11 Of U S Bankruptcy Code
Debtor-in-Possession Financing
Debtor-in-Possession Financing, aggregate principal amount	$ 35
Venoco, Inc.
Description of Operations
Percentage of common stock held		100.00%

ORGANIZATION AND SUMMARY OF S34

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Accounts Receivable (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)segment	Dec. 31, 2014USD ($)	Oct. 03, 2012$ / shares
Business Segment Information
Number of operating segments | segment	1
Accounts Receivable
Accounts Receivable, Net, Current	$ 10,610	$ 14,912
Venoco, Inc.
Description of Operations
Percentage of common stock held	100.00%
Accounts Receivable
Oil and natural gas sales related	$ 2,542	9,161
Joint interest billings related	423	259
Realized gains on derivatives	7,425	5,555
Other	320	37
Allowance for doubtful accounts	(100)	(100)
Accounts Receivable, Net, Current	$ 10,610	$ 14,912
Venoco, Inc. | Mr. Marquez
Basis of Presentation
Share price (in dollars per share) | $ / shares			$ 12.50

ORGANIZATION AND SUMMARY OF S35

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentration Risk (Details) $ in Thousands	Mar. 16, 2016USD ($)	Dec. 31, 2015USD ($)item	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Oil and Natural Gas Properties
Depletion expense		$ 22,000	$ 42,000	$ 46,000
Unproved costs transferred into the amortization base		8,600		4,000
Interest costs capitalized		$ 0	0	0
Discount rate applied to estimated future net revenues from oil and natural reserves (as a percent)		10.00%
Impairment of Oil and Gas Properties		$ 439,858	817
Accounts Payable and Accrued Liabilities, Current
Accounts Payable		4,488	5,497
Accrued Liabilities		5,376	3,850
Accrued Payroll and Bonus		5,111	4,948
Accrued Taxes		680	1,911
Notes payable		718	1,214
Revenue and Severance tax payable		947	1,581
Other		1,596	1,534
Accounts payable and accrued liabilities, current		37,916	20,535
General and Administrative Expenses
General and administrative costs directly related to acquisition, exploration and development activities		9,000	8,700	$ 23,000
Delaware Litigation
Accounts Payable and Accrued Liabilities, Current
Accrued Liabilities		19,000
Accounts Payable and Accrued Liabilities | Delaware Litigation | Forecast
Accounts Receivable - Insurance
Liability accrued under litigation	$ 19,000
Insurance Receivable | Delaware Litigation | Forecast
Accounts Receivable - Insurance
Estimate settlement, paid by insurers	16,500
General and administrative expense (income) | Delaware Litigation | Forecast
Accounts Receivable - Insurance
Payment owed in settlement	$ 2,500
Venoco, Inc
Oil and Natural Gas Properties
Impairment of Oil and Gas Properties		439,858	817
Accounts Payable and Accrued Liabilities, Current
Accounts payable and accrued liabilities, current		$ 37,916	$ 20,535
Accounts receivable | Customer concentration
Major customers
Number of major customers | item		2
Accounts receivable | Customer concentration | Two major customers
Major customers
Percentage of concentration risk		97.00%
Revenue | Customer concentration | Customer A
Major customers
Percentage of concentration risk		68.00%	54.00%	60.00%
Revenue | Customer concentration | Customer B
Major customers
Percentage of concentration risk		29.00%	43.00%	36.00%

ORGANIZATION AND SUMMARY OF S36

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Property, Plant, and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other property and equipment
Depreciation and amortization expense	$ 23,599	$ 44,064	$ 48,840
Other property and equipment
Other property and equipment
Depreciation and amortization expense	$ 1,600	$ 2,100	$ 2,800
Other property and equipment | Minimum
Other property and equipment
Estimated useful lives	P3Y
Other property and equipment | Maximum
Other property and equipment
Estimated useful lives	P25Y

ORGANIZATION AND SUMMARY OF S37

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - ASU Adoption (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
New Accounting Pronouncement or Change in Accounting Principle, Retrospective Adjustments [Abstract]
OTHER	$ 3,422	$ 4,069
Long-term debt, net of current portion	0	828,451
Accounting Standards Update ("ASU") 2015-03 | New Accounting Pronouncement, Early Adoption, Effect | Scenario Adjustment
New Accounting Pronouncement or Change in Accounting Principle, Retrospective Adjustments [Abstract]
OTHER	(13,600)	(11,600)
Long-term debt, net of current portion	(13,600)	(11,600)
Venoco, Inc.
New Accounting Pronouncement or Change in Accounting Principle, Retrospective Adjustments [Abstract]
OTHER	3,422	4,069
Long-term debt, net of current portion	0	557,872
Venoco, Inc. | Accounting Standards Update ("ASU") 2015-03 | New Accounting Pronouncement, Early Adoption, Effect | Scenario Adjustment
New Accounting Pronouncement or Change in Accounting Principle, Retrospective Adjustments [Abstract]
OTHER	(10,600)	(7,100)
Long-term debt, net of current portion	$ (10,600)	$ (7,100)

ORGANIZATION AND SUMMARY OF S38

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Discretionary matching contributions of annual compensation (as a percent)	90.00%
Matching contributions of participant contributions (as a percent)	100.00%
Compensation (as a percent)	5.00%
Matching contribution after first 5%	50.00%
Contributions made	$ 1.3	$ 1.7	$ 2

SALES OF PROPERTIES (Details)

SALES OF PROPERTIES (Details) - USD ($) $ in Thousands	Jul. 01, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
ACQUISITIONS AND SALES OF PROPERTIES
Proceeds provided by sale of oil and natural gas properties		$ 1,844	$ 196,534	$ 101,077
Venoco, Inc.
ACQUISITIONS AND SALES OF PROPERTIES
Proceeds provided by sale of oil and natural gas properties		$ 1,844	$ 196,534	$ 101,077
Sale of Montalvo Assets | Disposal Group, Disposed of by Sale, Not Discontinued Operations
ACQUISITIONS AND SALES OF PROPERTIES
Proceeds provided by sale of oil and natural gas properties	$ 200,200
Percentage of proceeds used to repay the debt		100.00%
Gain or loss recognized on sale of oil and natural gas properties		$ 0

DEBT (Details)

DEBT (Details) $ in Thousands	Jun. 11, 2015USD ($)	Apr. 02, 2015USD ($)item	Aug. 31, 2014USD ($)	Aug. 31, 2013	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Feb. 28, 2011USD ($)
LONG-TERM DEBT
Total long-term debt					$ 998,027	$ 828,451
Deferred Loan Costs					(13,631)	(11,614)
Less: current portion of long-term debt					(998,027)
Long-term debt, net of current portion					0	828,451
Interest expense					39,100	34,400	$ 21,500
Net gain on extinguishment of debt					67,515	(2,347)	(58,472)
Amortization of debt issuance costs and discounts and premiums					4,500
Venoco, Inc.
LONG-TERM DEBT
Number of debt instruments | item		3
Total long-term debt					686,877	557,872
Deferred Loan Costs					(10,623)	(7,128)
Less: current portion of long-term debt					(686,877)
Long-term debt, net of current portion					0	557,872
Dividend paid to DPC						3,905	15,800
Net gain on extinguishment of debt					$ 67,515	(2,347)	$ (38,549)
First lien secured notes
LONG-TERM DEBT
Interest rate (as a percent)					12.00%
Total long-term debt					$ 175,000
First lien secured notes | Venoco, Inc.
LONG-TERM DEBT
Interest rate (as a percent)					12.00%
Total long-term debt					$ 175,000
First lien secured notes | First redemption | Venoco, Inc.
LONG-TERM DEBT
Redemption price as a percentage of principal amount					109.00%
First lien secured notes | Final redemption | Venoco, Inc.
LONG-TERM DEBT
Redemption price as a percentage of principal amount					100.00%
Additional secured or unsecured debt | Maximum | Venoco, Inc.
LONG-TERM DEBT
Face value					$ 25,000
Second lien secured notes
LONG-TERM DEBT
Total long-term debt					139,880
Discount on notes					24,200
Accrued interest					9,300
Second lien secured notes | Venoco, Inc.
LONG-TERM DEBT
Total long-term debt					139,880
Additional second lien secured notes | Maximum | Venoco, Inc.
LONG-TERM DEBT
Face value					50,000
Additional third lien or unsecured debt | Maximum | Venoco, Inc.
LONG-TERM DEBT
Face value					150,000
Term Loan
LONG-TERM DEBT
Total long-term debt					74,398
Discount on notes					600
Term Loan | Venoco, Inc.
LONG-TERM DEBT
Total long-term debt					$ 74,398
Term Loan | LIBOR
LONG-TERM DEBT
Applicable margin (as a percent)					4.00%
Senior Notes | First lien secured notes | Venoco, Inc.
LONG-TERM DEBT
Face value		$ 175,000
Senior Notes | Second lien secured notes | Venoco, Inc.
LONG-TERM DEBT
Cash interest rate (as a percent)		8.875%			8.875%
Paid in kind interest rate (as a percent)		12.00%			12.00%
Face value		$ 150,000
Period for commencing interest payment		24 months
Senior Notes | Term Loan | Venoco, Inc.
LONG-TERM DEBT
Face value	$ 75,000	$ 75,000
Revolving credit agreement
LONG-TERM DEBT
Total long-term debt						65,000
Revolving credit agreement | Venoco, Inc.
LONG-TERM DEBT
Proceeds from issuance used for repayments of debt	72,000
Total long-term debt						65,000
8.875% senior notes
LONG-TERM DEBT
Interest rate (as a percent)					8.875%
Total long-term debt					$ 308,222	$ 500,000
Gross gain on extinguishment of debt					$ 44,000
8.875% senior notes | Venoco, Inc.
LONG-TERM DEBT
Interest rate (as a percent)					8.875%	8.875%		8.875%
Face value								$ 500,000
Proceeds from issuance used for repayments of debt	$ 194,000
Total long-term debt					$ 308,222	$ 500,000
Face value of debt redeemed		192,000
Extinguishment of accrued interest		$ 2,000
8.875% senior notes | Two year period beginning on February 15, 2015 | Venoco, Inc.
LONG-TERM DEBT
Redemption price as a percentage of principal amount					104.438%
8.875% senior notes | Two year period beginning on February 15, 2017 | Venoco, Inc.
LONG-TERM DEBT
Redemption price as a percentage of principal amount					100.00%
8.875% senior notes | Second lien secured notes
LONG-TERM DEBT
Gross gain on extinguishment of debt					$ 28,000
12.25% / 13.00% senior PIK toggle notes due 2018
LONG-TERM DEBT
Total long-term debt					314,158	275,065
Discount on notes					4,000	5,400
Accrued interest					$ 14,800	$ 13,000
12.25% / 13.00% senior PIK toggle notes due 2018 | Denver Parent Corporation
LONG-TERM DEBT
Cash interest rate (as a percent)				12.25%
Paid in kind interest rate (as a percent)				13.00%
Face value			$ 255,000
Percentage of interest paid in cash			25.00%
Percentage of interest paid in PIK			75.00%
Issuance price as a percentage of par value				97.304%
12.25% / 13.00% senior PIK toggle notes due 2018 | Three year period beginning on and after August 15, 2015 | Denver Parent Corporation
LONG-TERM DEBT
Redemption price as a percentage of principal amount					106.125%
12.25% / 13.00% senior PIK toggle notes due 2018 | Twelve month period beginning on August 15, 2017 | Denver Parent Corporation
LONG-TERM DEBT
Redemption price as a percentage of principal amount					100.00%
12.25% / 13.00% senior PIK toggle notes due 2018 | Minimum
LONG-TERM DEBT
Interest rate (as a percent)					12.25%	12.25%
12.25% / 13.00% senior PIK toggle notes due 2018 | Minimum | Denver Parent Corporation
LONG-TERM DEBT
Interest rate (as a percent)					12.25%
12.25% / 13.00% senior PIK toggle notes due 2018 | Maximum
LONG-TERM DEBT
Interest rate (as a percent)					13.00%
12.25% / 13.00% senior PIK toggle notes due 2018 | Maximum | Denver Parent Corporation
LONG-TERM DEBT
Interest rate (as a percent)					13.00%

DEBT - Maturities (Details)

DEBT - Maturities (Details) $ in Thousands	Dec. 31, 2015USD ($)
Annual maturities of long-term debt outstanding
2,017	$ 74,398
2,018	314,158
2,019	623,102
Total	1,011,658
Venoco, Inc.
Annual maturities of long-term debt outstanding
2,017	74,398
2,019	623,102
Total	$ 697,500

HEDGING AND DERIVATIVE FINANC42

HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS - Commodity derivative losses (gains) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
Commodity derivative losses (gains), net	$ (34,108)	$ (101,899)	$ 12,607
Commodity derivatives | Derivatives not designated as hedging instruments
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
Realized derivative losses (gains)	(78,510)	(83)	28,128
Unrealized commodity derivative losses (gains) for changes in fair value	44,402	(101,816)	(15,521)
Commodity derivative losses (gains), net	$ (34,108)	$ (101,899)	$ 12,607

HEDGING AND DERIVATIVE FINANC43

HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS - Oil derivatives (Details) $ in Millions	Feb. 11, 2016USD ($)	Dec. 31, 2015bbl / d$ / MMBTU
Forecast
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
Realized derivative gain | $	$ 34.6
Derivatives not designated as hedging instruments | Brent | Oil Swaps | January 1 - December 31, 2016
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
Nonmonetary notional amount | bbl / d		1,715
Weighted Avg. Prices (in dollars per bbl/MMBtu) | $ / MMBTU		96

HEDGING AND DERIVATIVE FINANC44

HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS - FV of Derivative Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
Current Assets Commodity derivatives:	$ 33,688	$ 48,298
Non current Assets Commodity derivatives:		29,793
Derivatives not designated as hedging instruments
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
Net derivative asset (liability)	33,688	78,091
Derivatives not designated as hedging instruments | Oil derivative contracts
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
Current Assets Commodity derivatives:	$ 33,688	48,298
Non current Assets Commodity derivatives:		$ 29,793

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014
Activities for the Company's asset retirement obligations
Asset retirement obligations at beginning of period	$ 30,851	$ 38,182
Revisions of estimated liabilities	1,975	(594)
Liabilities incurred or acquired		221
Liabilities settled or disposed	(375)	(9,449)
Accretion expense	2,150	2,491	$ 2,477
Asset retirement obligation at end of period	$ 30,851	$ 38,182	$ 38,182	$ 34,601	$ 30,851
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)				(1,325)	(500)
Long-term asset retirement obligations				$ 33,276	$ 30,351

CAPITAL STOCK (Details)

CAPITAL STOCK (Details) - $ / shares	1 Months Ended	12 Months Ended
	Oct. 31, 2012	Dec. 31, 2015	Dec. 31, 2014
CAPITAL STOCK
Issuance of common stock pursuant to Employee Stock Purchase Plan (in shares)			146,525
Common stock, shares outstanding		30,297,459	30,297,459
Granted (in shares)		0
Venoco, Inc.
CAPITAL STOCK
Common stock, shares outstanding		29,936,378	29,936,378
Mr. Marquez | Venoco, Inc.
CAPITAL STOCK
Right to receive cash per share (in dollars per share)	$ 12.50

SHARE-BASED PAYMENTS (Details)

SHARE-BASED PAYMENTS (Details) - 12 months ended Dec. 31, 2015 - $ / shares	Total	Total
SHARE-BASED PAYMENTS
ESOP restricted share units vesting period beginning with the participant's hire date or the date of the adoption of the ESOP, whichever is later	4 years
Stock Option Activity
Granted (in shares)	0
Options | Minimum
SHARE-BASED PAYMENTS
Exercise price (in dollars per share)	$ 12.50	$ 12.50
Exercise price of other than options (in dollars per share)		12.50
Weighted Average Exercise Price
Outstanding, end of period (in dollars per share)	$ 12.50
Options | Maximum
SHARE-BASED PAYMENTS
Life of awards	10 years
Restricted share unit awards
SHARE-BASED PAYMENTS
Vesting period	4 years
SAR
SHARE-BASED PAYMENTS
Life of awards	10 years
Exercise price of other than options (in dollars per share)		12.50
Weighted Average Exercise Price
Exercisable, end of period (in dollars per share)	$ 13.28
SAR | Awards that vest on the grant date
SHARE-BASED PAYMENTS
Vesting percentage	100.00%
SAR awards for each Venoco common share held
SHARE-BASED PAYMENTS
Life of awards	10 years
Exercise price (in dollars per share)	$ 12.50	$ 12.50
Vesting percentage	100.00%
Weighted Average Exercise Price
Outstanding, end of period (in dollars per share)	$ 12.50

SHARE-BASED PAYMENTS - SARs by

SHARE-BASED PAYMENTS - SARs by range of exercise price (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
$12.51 - $20.00
Weighted Average Grant Date Fair
Weighted Average Remaining Contractual Life, Exercisable	2 years 8 months 12 days
$12.51 - $20.00 | Minimum
Weighted Average Grant Date Fair
Exercise price, low end of range (in dollars per share)	$ 12.51
$12.51 - $20.00 | Maximum
Weighted Average Grant Date Fair
Exercise price, high end of range (in dollars per share)	$ 20
Employee Stock Ownership Plan
Shares
Outstanding, start of period (in shares)	263,874	196,679
Granted (in shares)		146,525
Vested or exercised (in shares)	(11,933)
Cancelled and other (in shares)	(5,858)	(79,330)
Outstanding, end of period (in shares)	269,949	263,874
Weighted Average Grant Date Fair
Granted (in dollars per share)		$ 12.24
Cancelled and other (in dollars per share)	$ 8.33	$ 8.33
Rights to receive
Shares
Outstanding, start of period (in shares)	105,745	1,241,264
Vested or exercised (in shares)	(105,362)	(1,092,676)
Cancelled and other (in shares)	(133)	(42,843)
Outstanding, end of period (in shares)	250	105,745
Weighted Average Grant Date Fair
Vested or exercised (in dollars per share)	$ 12.50	$ 12.50
Cancelled and other (in dollars per share)	$ 12.50	$ 12.50
Restricted share unit awards
Shares
Outstanding, start of period (in shares)	465,216	778,065
Granted (in shares)		147,802
Vested or exercised (in shares)	(192,916)	(241,522)
Cancelled and other (in shares)	(14,016)	(219,129)
Outstanding, end of period (in shares)	258,284	465,216
Weighted Average Grant Date Fair
Granted (in dollars per share)		$ 12.24
Vested or exercised (in dollars per share)	$ 8.33	8.33
Cancelled and other (in dollars per share)	$ 8.33	$ 8.33
SAR
Shares
Outstanding, start of period (in shares)	3,556,523	4,345,594
Granted (in shares)		1,411,772
Vested or exercised (in shares)		(114,835)
Cancelled and other (in shares)	(537,533)	(2,086,008)
Outstanding, end of period (in shares)	3,018,990	3,556,523
Exercisable, end of period (in shares)	2,105,720	2,534,312
Weighted Average Grant Date Fair
Granted (in dollars per share)		$ 7.42
Vested or exercised (in dollars per share)		8.33
Cancelled and other (in dollars per share)	$ 2.70	$ 2.70
Number Outstanding (in shares)	3,018,990
Number Exercisable (in shares)	2,105,720	2,534,312
Weighted Average Remaining Contractual Life, Outstanding	3 years 7 months 6 days
Weighted Average Remaining Contractual Life, Exercisable	3 years
Weighted-Average Exercise Prices, Outstanding	$ 13.28
Weighted-Average Exercise Prices, Exercisable	$ 13.28
SAR | $8.33
Shares
Exercisable, end of period (in shares)	109,102
Weighted Average Grant Date Fair
Exercise price, low end of range (in dollars per share)	$ 8.33
Number Outstanding (in shares)	287,155
Number Exercisable (in shares)	109,102
Weighted Average Remaining Contractual Life, Outstanding	4 years 6 months
Weighted Average Remaining Contractual Life, Exercisable	4 years 6 months
Weighted-Average Exercise Prices, Outstanding	$ 8.33
Weighted-Average Exercise Prices, Exercisable	$ 8.33
SAR | $12.24
Shares
Exercisable, end of period (in shares)	171,027
Weighted Average Grant Date Fair
Exercise price, high end of range (in dollars per share)	$ 12.24
Number Outstanding (in shares)	684,030
Number Exercisable (in shares)	171,027
Weighted Average Remaining Contractual Life, Outstanding	5 years 6 months
Weighted Average Remaining Contractual Life, Exercisable	5 years 6 months
Weighted-Average Exercise Prices, Outstanding	$ 12.24
Weighted-Average Exercise Prices, Exercisable	$ 12.24
SAR | $12.50
Shares
Exercisable, end of period (in shares)	1,495,309
Weighted Average Grant Date Fair
Exercise price, high end of range (in dollars per share)	$ 12.50
Number Outstanding (in shares)	1,495,559
Number Exercisable (in shares)	1,495,309
Weighted Average Remaining Contractual Life, Outstanding	2 years 8 months 12 days
Weighted Average Remaining Contractual Life, Exercisable	2 years 8 months 12 days
Weighted-Average Exercise Prices, Outstanding	$ 12.50
Weighted-Average Exercise Prices, Exercisable	$ 12.50
SAR | $12.51 - $20.00
Shares
Exercisable, end of period (in shares)	330,282
Weighted Average Grant Date Fair
Number Outstanding (in shares)	552,246
Number Exercisable (in shares)	330,282
Weighted Average Remaining Contractual Life, Outstanding	3 years 4 months 24 days
Weighted-Average Exercise Prices, Outstanding	$ 19.30
Weighted-Average Exercise Prices, Exercisable	$ 18.88

SHARE-BASED PAYMENTS - Assumpti

SHARE-BASED PAYMENTS - Assumptions (Details) - SAR	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Assumptions used to compute the grant date fair value
Risk free interest rates, minimum (as a percent)		0.12%
Risk free interest rates, maximum (as a percent)		1.97%
Estimated volatilities, minimum (as a percent)		45.00%
Estimated volatilities, maximum (as a percent)		60.00%
Dividend yield		0.00%
Period to determine expected volatility	7 years
Minimum
Assumptions used to compute the grant date fair value
Expected lives		6 months
Maximum
Assumptions used to compute the grant date fair value
Expected lives		6 years 6 months

SHARE-BASED PAYMENTS - Summary

SHARE-BASED PAYMENTS - Summary shared-based comp liability (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Summary of share-based compensation liability
Share-based compensation liability at beginning of period	$ 2,884	$ 37,444
Total share-based compensation costs (income)	(607)	(13,815)
Payout	(1,774)	(19,113)
APIC Adjustment	(498)	(1,632)
Share-based compensation liability at end of period	5	2,884
Less: current share-based compensation liability	(2)	(2,236)
Long-term current share-based compensation liability	$ 3	$ 648

SHARE-BASED PAYMENTS - Composit

SHARE-BASED PAYMENTS - Composition share-based compensation liability (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based compensation liability
Current Liability	$ 2	$ 2,236
Long Term Liability	3	648
Total Liability	5	2,884	$ 37,444
Employee Stock Ownership Plan
Share-based compensation liability
Long Term Liability	3	204
Total Liability	3	204
Rights to receive
Share-based compensation liability
Current Liability	1	1,846
Total Liability	1	1,846
Restricted share unit awards
Share-based compensation liability
Current Liability	1	390
Total Liability	$ 1	390
SAR
Share-based compensation liability
Long Term Liability		444
Total Liability		$ 444

SHARE-BASED PAYMENTS - Share-ba

SHARE-BASED PAYMENTS - Share-based compensation costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
SHARE-BASED PAYMENTS
Total share-based compensation costs (income)	$ (607)	$ (13,814)	$ 28,461
Less: share-based compensation costs capitalized (reduced)	217	5,557	(5,902)
Share-based compensation expense (income), net	(390)	(8,257)	22,559
General and administrative expense (income)
SHARE-BASED PAYMENTS
Total share-based compensation costs (income)	(462)	(10,490)	25,206
Oil and natural gas production expense (income)
SHARE-BASED PAYMENTS
Total share-based compensation costs (income)	$ (145)	$ (3,324)	$ 3,255

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
FAIR VALUE MEASUREMENTS
Commodity derivative contracts, assets	$ 33,688
Share-based compensation	(5)	$ (2,884)	$ (37,444)
Changes in fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy
Fair value liability, beginning of period	(1,038)	(20,928)
Transfers into Level 3	(588)	(5,552)
Transfers out of Level 3	1,070	10,072
Change in fair value of Level 3	551	15,370
Fair value liability, end of period	(5)	$ (1,038)
Level 2
FAIR VALUE MEASUREMENTS
Commodity derivative contracts, assets	33,688
Level 3
FAIR VALUE MEASUREMENTS
Share-based compensation	$ (5)

FAIR VALUE MEASUREMENTS - FV of

FAIR VALUE MEASUREMENTS - FV of financial instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Feb. 28, 2011
First lien secured notes
FAIR VALUE MEASUREMENTS
Interest rate (as a percent)	12.00%
Second lien secured notes
FAIR VALUE MEASUREMENTS
Accrued interest	$ 9,300
8.875% senior notes
FAIR VALUE MEASUREMENTS
Interest rate (as a percent)	8.875%
12.25% / 13.00% senior PIK toggle notes due 2018
FAIR VALUE MEASUREMENTS
Accrued interest	$ 14,800	$ 13,000
12.25% / 13.00% senior PIK toggle notes due 2018 | Minimum
FAIR VALUE MEASUREMENTS
Interest rate (as a percent)	12.25%	12.25%
12.25% / 13.00% senior PIK toggle notes due 2018 | Maximum
FAIR VALUE MEASUREMENTS
Interest rate (as a percent)	13.00%
Denver Parent Corporation | 12.25% / 13.00% senior PIK toggle notes due 2018 | Minimum
FAIR VALUE MEASUREMENTS
Interest rate (as a percent)	12.25%
Denver Parent Corporation | 12.25% / 13.00% senior PIK toggle notes due 2018 | Maximum
FAIR VALUE MEASUREMENTS
Interest rate (as a percent)	13.00%
Denver Parent Corporation | Carrying Value | 12.25% / 13.00% senior PIK toggle notes due 2018
FAIR VALUE MEASUREMENTS
Long-term debt	$ 318,114	$ 275,065
Accrued interest	14,800
Denver Parent Corporation | Fair Value | 12.25% / 13.00% senior PIK toggle notes due 2018
FAIR VALUE MEASUREMENTS
Long-term debt	$ 1,517	$ 120,369
Venoco, Inc. | First lien secured notes
FAIR VALUE MEASUREMENTS
Interest rate (as a percent)	12.00%
Venoco, Inc. | 8.875% senior notes
FAIR VALUE MEASUREMENTS
Interest rate (as a percent)	8.875%	8.875%	8.875%
Venoco, Inc. | Second Lien Secured 8.87 Percent Or 12 Percent P I K Notes Due February 2019 [Member] | Minimum
FAIR VALUE MEASUREMENTS
Interest rate (as a percent)	8.875%
Venoco, Inc. | Second Lien Secured 8.87 Percent Or 12 Percent P I K Notes Due February 2019 [Member] | Maximum
FAIR VALUE MEASUREMENTS
Interest rate (as a percent)	12.00%
Venoco, Inc. | Carrying Value | First lien secured notes
FAIR VALUE MEASUREMENTS
Long-term debt	$ 175,000
Venoco, Inc. | Carrying Value | Term Loan
FAIR VALUE MEASUREMENTS
Long-term debt	75,000
Venoco, Inc. | Carrying Value | Revolving credit agreement
FAIR VALUE MEASUREMENTS
Long-term debt		$ 65,000
Venoco, Inc. | Carrying Value | 8.875% senior notes
FAIR VALUE MEASUREMENTS
Long-term debt	308,222	500,000
Venoco, Inc. | Carrying Value | Second Lien Secured 8.87 Percent Or 12 Percent P I K Notes Due February 2019 [Member]
FAIR VALUE MEASUREMENTS
Long-term debt	164,099
Accrued interest	9,300
Venoco, Inc. | Fair Value | First lien secured notes
FAIR VALUE MEASUREMENTS
Long-term debt	138,444
Venoco, Inc. | Fair Value | Term Loan
FAIR VALUE MEASUREMENTS
Long-term debt	75,000
Venoco, Inc. | Fair Value | Revolving credit agreement
FAIR VALUE MEASUREMENTS
Long-term debt		65,000
Venoco, Inc. | Fair Value | 8.875% senior notes
FAIR VALUE MEASUREMENTS
Long-term debt	47,312	$ 262,000
Venoco, Inc. | Fair Value | Second Lien Secured 8.87 Percent Or 12 Percent P I K Notes Due February 2019 [Member]
FAIR VALUE MEASUREMENTS
Long-term debt	$ 84,409

INCOME TAXES - Carryovers (Deta

INCOME TAXES - Carryovers (Details)	12 Months Ended
	Dec. 31, 2015USD ($)
Operating loss carryovers
Net operating loss carryovers for financial reporting purposes	$ 517,000,000
Tax deductions for compensation expense for financial reporting purposes	$ 40,000,000
Period for which net operating loss carryovers may be carried back	2 years
Period for which net operating loss carryovers may be carried forward	20 years
Liability for uncertain tax positions	$ 0
Venoco, Inc.
Operating loss carryovers
Net operating loss carryovers for financial reporting purposes	395,000,000
Federal
Operating loss carryovers
Net operating loss carryovers	557,000,000
Federal | Venoco, Inc.
Operating loss carryovers
Net operating loss carryovers	$ 435,000,000

INCOME TAXES - Income tax provi

INCOME TAXES - Income tax provision (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of the income tax provision (benefit)
Federal statutory rate (as a percent)	35.00%	35.00%	35.00%
Income tax expense (benefit) at federal statutory rate	$ (176,753)	$ 29,601	$ (9,954)
State income tax expense (benefit)	(17,061)	2,253	(801)
Other	1,043	267	(435)
Valuation allowance	192,771	(32,121)	11,190
Deferred income tax assets:
Net operating losses	203,079	178,836
Unrealized commodity derivative losses	83,791
Accrued liabilities	1,726	622
Share-based compensation	2	1,086
Charitable contributions	1,760	2,038
Other current assets	1,718	691
Asset retirement obligation	13,279	11,620
Alternative minimum tax credits	10,585	10,585
Valuation allowance	(301,886)	(109,122)
Deferred income tax assets	14,054	96,356
Deferred income tax liabilities:
Oil and gas properties		(66,856)
Unrealized commodity derivative gains	(12,983)	(28,086)
Prepaid expenses	(1,041)	(1,127)
Investments	(30)	(287)
Deferred income tax liabilities	(14,054)	(96,356)
Venoco, Inc.
Reconciliation of the income tax provision (benefit)
Income tax expense (benefit) at federal statutory rate	(162,527)	42,153	5,012
State income tax expense (benefit)	(15,688)	3,208	403
Other	1,043	105	(378)
Valuation allowance	177,172	(45,466)	$ (5,037)
Deferred income tax assets:
Net operating losses	157,385	148,134
Unrealized commodity derivative losses	83,791
Accrued liabilities	1,726	622
Share-based compensation	2	1,086
Charitable contributions	1,760	2,038
Other current assets	703	690
Asset retirement obligation	13,279	11,620
Alternative minimum tax credits	10,585	10,585
Valuation allowance	(255,177)	(78,419)
Deferred income tax assets	14,054	96,356
Deferred income tax liabilities:
Oil and gas properties		(66,856)
Unrealized commodity derivative gains	(12,983)	(28,086)
Prepaid expenses	(1,041)	(1,127)
Investments	(30)	(287)
Deferred income tax liabilities	$ (14,054)	$ (96,356)

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2006
6267 Carpinteria
RELATED PARTY TRANSACTIONS
Membership interest (as a percent)				100.00%
Minimum lease payments			$ 0.2
TimBer, LLC
RELATED PARTY TRANSACTIONS
Cost incurred related to the non-exclusive aircraft sublease agreement	$ 0.6	$ 0.7	$ 0.7

COMMITMENTS (Details)

COMMITMENTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Future minimum lease payments under operating leases
2,016	$ 1.9
2,017	1.9
2,018	2.2
2,019	2.5
2,020	2.4
Thereafter	5.1
Rent expense
Net rent expense	$ 1.5	$ 1.7	$ 2

CONTINGENCIES (Details)

CONTINGENCIES (Details) $ / shares in Units, $ in Millions	Mar. 16, 2016USD ($)	Jan. 16, 2012lawsuit	Mar. 31, 2014USD ($)	Dec. 31, 2013person	Aug. 31, 2011lawsuit$ / shares
Delaware Litigation | Venoco, Inc.
CONTINGENCIES
Number of lawsuits filed | lawsuit		5			5
Delaware Litigation | General and administrative expense (income) | Forecast
CONTINGENCIES
Payment owed in settlement	$ 2.5
Delaware Litigation | Accounts Payable and Accrued Liabilities | Forecast
CONTINGENCIES
Liability accrued under litigation	19
Delaware Litigation | Insurance Receivable | Forecast
CONTINGENCIES
Estimate settlement, paid by insurers	$ 16.5
Delaware Litigation | Mr. Marquez | Venoco, Inc.
CONTINGENCIES
Price per share offered for shares of common stock proposed to be acquired by related party of which it is not the beneficial owner (in dollars per share) | $ / shares					$ 12.50
Denbury Arbitration
CONTINGENCIES
Amount of arbitration award			$ 1.8
Number of judges in arbitration panel | person				3
Colorado Litigation | Venoco, Inc.
CONTINGENCIES
Number of lawsuits filed | lawsuit		3

QUARTERLY FINANCIAL DATA (UNA60

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
QUARTERLY FINANCIAL DATA (UNAUDITED)
Revenues	$ 9,278	$ 11,154	$ 19,870	$ 20,418	$ 36,322	$ 57,851	$ 67,039	$ 62,997	$ 60,720	$ 224,209	$ 317,502
Income (loss) from operations	(119,123)	(205,077)	(156,225)	(12,749)	7,406	23,660	24,293	20,977	(493,174)	76,336	134,033
Net income (loss)	(139,674)	(214,179)	(129,759)	(21,397)	70,963	30,231	(17,493)	872	(505,009)	84,574	(28,440)
Venoco, Inc.
QUARTERLY FINANCIAL DATA (UNAUDITED)
Revenues	9,278	11,154	19,870	20,418	36,322	57,851	67,039	62,997	60,720	224,209	317,502
Income (loss) from operations	(119,122)	(205,077)	(156,224)	(12,681)	7,442	23,711	24,378	21,231	(493,104)	76,762	134,294
Net income (loss)	$ (129,427)	$ (203,322)	$ (119,820)	$ (11,794)	$ 80,105	$ 39,525	$ (8,746)	$ 9,553	$ (464,363)	$ 120,437	$ 14,319

SUPPLEMENTAL INFORMATION ON O61

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) - Capitalized Costs (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / bbl	Dec. 31, 2014USD ($)$ / bbl	Dec. 31, 2013USD ($)$ / bbl
Capitalized Costs of Oil and Natural Gas Properties
Unevaluated properties		$ 8,360	$ 12,939
Properties subject to amortization	$ 1,903,172	1,866,415	1,991,644
Total capitalized costs	1,903,172	1,874,775	2,004,583
Accumulated depletion	(1,860,217)	(1,400,738)	(1,357,927)
Net oil and gas properties	42,955	474,037	646,656
Depletion expense	$ 22,000	$ 42,000	$ 46,000
Depletion expense, per equivalent barrel of oil (in dollars per barrel of oil) | $ / bbl	15.15	15.54	13.27
Capitalized Costs Incurred
General and administrative costs	$ 9,000	$ 8,700	$ 23,000
Asset retirement costs	1,300	4,600	500
Property acquisition and leasehold costs:
Unevaluated property		419	748
Proved property	4,429	179	172
Exploration costs	27	28,386	41,588
Development costs	24,186	47,754	54,525
Total costs incurred	$ 28,642	$ 76,738	$ 97,033

SUPPLEMENTAL INFORMATION ON O62

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) - Reserves (Details)	12 Months Ended
	Dec. 31, 2015$ / bbl$ / MMBTUitemMBbls	Dec. 31, 2014$ / bbl$ / MMBTUMBbls	Dec. 31, 2013$ / bbl$ / MMBTUMBbls
Disclosure of Other Reserve Information [Abstract]
Number of additional undeveloped locations | item	2
Crude Oil, Liquids and Condensate (MBbls)
Net proved reserves
Beginning of the year reserves	38,560	50,774	50,435
Revisions of previous estimates	(24,891)	(3,525)	(1,232)
Extensions and discoveries		281	4,750
Production	(1,383)	(2,556)	(3,179)
Sales of reserves in place		(6,414)
End of year reserves	12,286	38,560	50,774
Proved developed reserves:
Beginning of year	26,287	34,508	35,115
End of year	12,286	26,287	34,508
Proved undeveloped reserves:
Beginning of year	12,273	16,266	15,320
End of year		12,273	16,266
Disclosure of Other Reserve Information [Abstract]
Period for consideration of arithmetic average of the first day of the month oil and gas prices	12 months	12 months	12 months
Arithmetic average price (in dollars per Bbl or MMBtu) | $ / bbl	50.28	94.99	96.78
Barrels of oil equivalent of proved reserves related to revisionary interest	26,287	34,508	35,115
Crude Oil, Liquids and Condensate (MBbls) | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Hastings Complex Sale
Disclosure of Other Reserve Information [Abstract]
Working interest (as a percent)	22.45%
Oil (Bbl)
Disclosure of Other Reserve Information [Abstract]
Average realized price (in dollars per Bbl or MMBtu) | $ / bbl	38.32	86.69	98.37
Natural gas liquids (Bbl)
Disclosure of Other Reserve Information [Abstract]
Average realized price (in dollars per Bbl or MMBtu) | $ / bbl	32.28	71.12	79.04
Liquid reserves as a percentage of total reserves	5.80%	3.80%	3.40%
Natural Gas (MMcf)
Net proved reserves
Beginning of the year reserves	10,933	13,716	10,850
Revisions of previous estimates	(5,574)	986	2,149
Extensions and discoveries			1,832
Production	(418)	(884)	(1,115)
Sales of reserves in place		(2,885)
End of year reserves	4,941	10,933	13,716
Proved developed reserves:
Beginning of year	8,941	10,394	7,255
End of year	4,941	8,941	10,394
Proved undeveloped reserves:
Beginning of year	1,992	3,322	3,595
End of year		1,992	3,322
Disclosure of Other Reserve Information [Abstract]
Arithmetic average price (in dollars per Bbl or MMBtu) | $ / MMBTU	2.58	4.35	3.67
Average realized price (in dollars per Bbl or MMBtu) | $ / MMBTU	2.96	5.21	4.41
Barrels of oil equivalent of proved reserves related to revisionary interest	8,941	10,394	7,255

SUPPLEMENTAL INFORMATION ON O63

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) - Cash flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
Discount rate applied to cash flow amounts in computation of standardized measure of discounted future net cash flows (as a percent)	10.00%
Standardized measure of discounted future net cash flows
Future cash inflows				$ 480,776	$ 3,375,871	$ 5,020,925
Future production costs				(383,054)	(1,791,740)	(1,829,168)
Future development and abandonment costs				(125,235)	(213,927)	(271,746)
Future income taxes					(241,120)	(775,850)
Future net cash flows				(27,513)	1,129,084	2,144,161
10% annual discount for estimated timing of cash flows				44,958	(480,930)	(990,444)
Standardized measure of discounted future net cash flows	$ 648,154	$ 1,153,717	$ 1,157,452	$ 17,445	$ 648,154	$ 1,153,717
Changes in the standardized measure of discounted future net cash flows
Beginning of the year	648,154	1,153,717	1,157,452
Changes in prices and production costs	(744,015)	(487,233)	(14,656)
Revisions of previous quantity estimates	(115,683)	(70,662)	(26,234)
Changes in future development costs	(13,240)	(32,767)	(33,958)
Development costs incurred during the period	120,931	42,664	31,485
Extensions, discoveries and improved recovery, net of related costs		7,323	109,868
Sales of oil and natural gas, net of production costs	329	(141,903)	(232,472)
Accretion of discount	71,427	142,344	145,483
Net change in income taxes	86,158	218,027	48,095
Sale of reserves in place		(189,466)
Production timing and other	(36,616)	6,110	(31,346)
End of year	$ 17,445	$ 648,154	$ 1,153,717

GUARANTOR FINANCIAL INFORMATI64

GUARANTOR FINANCIAL INFORMATION (Details) - item	Dec. 31, 2015	Dec. 31, 2014
GUARANTOR FINANCIAL INFORMATION
Percentage of ownership interest of guarantor subsidiaries	100.00%
First lien secured notes
GUARANTOR FINANCIAL INFORMATION
Interest rate (as a percent)	12.00%
8.875% senior notes
GUARANTOR FINANCIAL INFORMATION
Interest rate (as a percent)	8.875%
8.875% senior notes | Venoco, Inc
GUARANTOR FINANCIAL INFORMATION
Interest rate (as a percent)	8.875%
12.25% / 13.00% senior PIK toggle notes due 2018
GUARANTOR FINANCIAL INFORMATION
Number of guarantors	0
12.25% / 13.00% senior PIK toggle notes due 2018 | Minimum
GUARANTOR FINANCIAL INFORMATION
Interest rate (as a percent)	12.25%	12.25%
12.25% / 13.00% senior PIK toggle notes due 2018 | Maximum
GUARANTOR FINANCIAL INFORMATION
Interest rate (as a percent)	13.00%
12.25% / 13.00% senior PIK toggle notes due 2018 | Denver Parent Corporation | Minimum
GUARANTOR FINANCIAL INFORMATION
Interest rate (as a percent)	12.25%
12.25% / 13.00% senior PIK toggle notes due 2018 | Denver Parent Corporation | Maximum
GUARANTOR FINANCIAL INFORMATION
Interest rate (as a percent)	13.00%

GUARANTOR FINANCIAL INFORMATI65

GUARANTOR FINANCIAL INFORMATION - Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CURRENT ASSETS:
Cash and cash equivalents	$ 90,297	$ 15,656	$ 17,336	$ 54,318
Restricted funds	79,589
Accounts receivable	10,610	14,912
Insurance receivable	16,500
Inventories	1,452	3,370
Other current assets	3,859	4,721
Commodity derivatives	33,688	48,298
Total current assets	235,995	86,957
PROPERTY, PLANT & EQUIPMENT, NET	55,991	488,514
COMMODITY DERIVATIVES		29,793
OTHER	3,422	4,069
TOTAL ASSETS	295,408	609,333
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	37,916	20,535
Interest payable	20,912	17,329
Share-based compensation	2	2,236
Current portion of long-term debt	998,027
Total current liabilities	1,056,857	40,100
LONG-TERM DEBT	0	828,451
ASSET RETIREMENT OBLIGATIONS	33,276	30,351
SHARE-BASED COMPENSATION	3	648
Total liabilities	1,090,136	899,550
TOTAL STOCKHOLDERS’ EQUITY (DEFICIT)	(794,728)	(290,217)	(376,423)	(351,836)
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	295,408	609,333
Eliminations
CURRENT ASSETS:
INVESTMENTS IN AFFILIATES	(563,401)	(563,401)
TOTAL ASSETS	(563,401)	(563,401)
CURRENT LIABILITIES:
INTERCOMPANY PAYABLES (RECEIVABLES)	36	36
Total liabilities	36	36
TOTAL STOCKHOLDERS’ EQUITY (DEFICIT)	(563,437)	(563,437)
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	(563,401)	(563,401)
Venoco, Inc.
CURRENT ASSETS:
Cash and cash equivalents	90,165	15,455	828	53,818
Restricted funds	79,589
Accounts receivable	10,610	14,912
Insurance receivable	16,500
Inventories	1,452	3,370
Other current assets	3,859	4,715
Commodity derivatives	33,688	48,298
Total current assets	235,863	86,750
PROPERTY, PLANT & EQUIPMENT, NET	55,991	488,514
COMMODITY DERIVATIVES		29,793
OTHER	3,422	4,069
TOTAL ASSETS	295,276	609,126
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	37,916	20,535
Interest payable	20,912	17,329
Share-based compensation	2	2,236
Current portion of long-term debt	686,877
Total current liabilities	745,707	40,100
LONG-TERM DEBT	0	557,872
ASSET RETIREMENT OBLIGATIONS	33,276	30,351
SHARE-BASED COMPENSATION	3	648
Total liabilities	778,986	628,971
TOTAL STOCKHOLDERS’ EQUITY (DEFICIT)	(483,710)	(19,845)	(138,009)	(295,658)
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	295,276	609,126
Venoco, Inc
CURRENT ASSETS:
Cash and cash equivalents	90,165	15,455	$ 828	$ 53,818
Restricted funds	79,589
Accounts receivable	10,149	14,140
Insurance receivable	16,500
Inventories	1,452	3,370
Other current assets	3,859	4,715
Commodity derivatives	33,688	48,298
Total current assets	235,402	85,978
PROPERTY, PLANT & EQUIPMENT, NET	222,942	654,549
COMMODITY DERIVATIVES		29,793
INVESTMENTS IN AFFILIATES	563,401	563,401
OTHER	3,363	4,010
TOTAL ASSETS	1,025,108	1,337,731
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	37,916	20,535
Interest payable	20,912	17,329
Share-based compensation	2	2,236
Current portion of long-term debt	686,877
Total current liabilities	745,707	40,100
LONG-TERM DEBT		557,872
ASSET RETIREMENT OBLIGATIONS	30,727	27,906
SHARE-BASED COMPENSATION	3	648
INTERCOMPANY PAYABLES (RECEIVABLES)	746,611	735,845
Total liabilities	1,523,048	1,362,371
TOTAL STOCKHOLDERS’ EQUITY (DEFICIT)	(497,940)	(24,640)
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	1,025,108	1,337,731
Guarantor Subsidiaries
CURRENT ASSETS:
Accounts receivable	36	56
Total current assets	36	56
PROPERTY, PLANT & EQUIPMENT, NET	(184,444)	(184,362)
OTHER	59	59
TOTAL ASSETS	(184,349)	(184,247)
CURRENT LIABILITIES:
ASSET RETIREMENT OBLIGATIONS	1,737	1,652
INTERCOMPANY PAYABLES (RECEIVABLES)	(655,781)	(655,326)
Total liabilities	(654,044)	(653,674)
TOTAL STOCKHOLDERS’ EQUITY (DEFICIT)	469,695	469,427
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	(184,349)	(184,247)
Non-Guarantor Subsidiary
CURRENT ASSETS:
Accounts receivable	425	716
Total current assets	425	716
PROPERTY, PLANT & EQUIPMENT, NET	17,493	18,327
TOTAL ASSETS	17,918	19,043
CURRENT LIABILITIES:
ASSET RETIREMENT OBLIGATIONS	812	793
INTERCOMPANY PAYABLES (RECEIVABLES)	(90,866)	(80,555)
Total liabilities	(90,054)	(79,762)
TOTAL STOCKHOLDERS’ EQUITY (DEFICIT)	107,972	98,805
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	$ 17,918	$ 19,043

GUARANTOR FINANCIAL INFORMATI66

GUARANTOR FINANCIAL INFORMATION - Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REVENUES:
Oil and natural gas sales									$ 58,485	$ 222,052	$ 313,373
Other									2,235	2,157	4,129
Total revenues	$ 9,278	$ 11,154	$ 19,870	$ 20,418	$ 36,322	$ 57,851	$ 67,039	$ 62,997	60,720	224,209	317,502
EXPENSES:
Lease operating expense									54,367	72,337	77,786
Production and property taxes									4,653	7,611	3,521
Transportation expense									201	201	181
Depletion, depreciation and amortization									23,599	44,064	48,840
Ceiling test and other impairments									439,858	817
Accretion of asset retirement obligations									2,150	2,491	2,477
General and administrative, net of amounts capitalized									29,066	20,352	50,664
Total expenses									553,894	147,873	183,469
Income (loss) from operations	(119,123)	(205,077)	(156,225)	(12,749)	7,406	23,660	24,293	20,977	(493,174)	76,336	134,033
FINANCING COSTS AND OTHER:
Interest expense, net									108,278	87,025	86,640
Amortization of deferred loan costs									5,180	4,289	4,754
Loss (gain) on extinguishment of debt									(67,515)	2,347	58,472
Commodity derivative losses (gains), net									(34,108)	(101,899)	12,607
Total financing costs and other									11,835	(8,238)	162,473
Income (loss) before income taxes									(505,009)	84,574	(28,440)
Net income (loss)	(139,674)	(214,179)	(129,759)	(21,397)	70,963	30,231	(17,493)	872	(505,009)	84,574	(28,440)
Eliminations
REVENUES:
Other									(5,414)	(6,194)	(13,203)
Total revenues									(5,414)	(6,194)	(13,203)
EXPENSES:
Transportation expense									(5,021)	(5,816)	(12,832)
General and administrative, net of amounts capitalized									(392)	(378)	(371)
Total expenses									(5,413)	(6,194)	(13,203)
Income (loss) from operations									(1)
FINANCING COSTS AND OTHER:
Equity in subsidiary income									(5,849)	(5,954)	(10,843)
Income (loss) before income taxes									(5,850)	(5,954)	(10,843)
Net income (loss)									(5,850)	(5,954)	(10,843)
Venoco, Inc.
REVENUES:
Oil and natural gas sales									58,485	222,052	313,373
Other									2,235	2,157	4,129
Total revenues	9,278	11,154	19,870	20,418	36,322	57,851	67,039	62,997	60,720	224,209	317,502
EXPENSES:
Lease operating expense									54,367	72,337	77,786
Production and property taxes									4,653	7,611	3,521
Transportation expense									201	201	181
Depletion, depreciation and amortization									23,599	44,064	48,840
Ceiling test and other impairments									439,858	817
Accretion of asset retirement obligations									2,150	2,491	2,477
General and administrative, net of amounts capitalized									28,996	19,926	50,403
Total expenses									553,824	147,447	183,208
Income (loss) from operations	(119,122)	(205,077)	(156,224)	(12,681)	7,442	23,711	24,378	21,231	(493,104)	76,762	134,294
FINANCING COSTS AND OTHER:
Interest expense, net									69,187	52,609	65,114
Amortization of deferred loan costs									3,695	3,268	3,705
Loss (gain) on extinguishment of debt									(67,515)	2,347	38,549
Commodity derivative losses (gains), net									(34,108)	(101,899)	12,607
Total financing costs and other									(28,741)	(43,675)	119,975
Income (loss) before income taxes									(464,363)	120,437	14,319
Net income (loss)	$ (129,427)	$ (203,322)	$ (119,820)	$ (11,794)	$ 80,105	$ 39,525	$ (8,746)	$ 9,553	(464,363)	120,437	14,319
Venoco, Inc
REVENUES:
Oil and natural gas sales									57,893	220,914	312,140
Other									500	479	1,259
Total revenues									58,393	221,393	313,399
EXPENSES:
Lease operating expense									51,072	68,829	75,144
Production and property taxes									4,402	7,337	3,216
Transportation expense									5,186	6,004	13,001
Depletion, depreciation and amortization									22,657	43,126	47,939
Ceiling test and other impairments									439,858	817
Accretion of asset retirement obligations									1,995	2,321	2,319
General and administrative, net of amounts capitalized									28,895	19,761	50,248
Total expenses									554,065	148,195	191,867
Income (loss) from operations									(495,672)	73,198	121,532
FINANCING COSTS AND OTHER:
Interest expense, net									76,051	58,648	69,841
Amortization of deferred loan costs									3,695	3,268	3,705
Loss (gain) on extinguishment of debt									(67,515)	2,347	38,549
Commodity derivative losses (gains), net									(34,108)	(101,899)	12,607
Total financing costs and other									(21,877)	(37,636)	124,702
Equity in subsidiary income									5,849	5,954	10,843
Income (loss) before income taxes									(467,946)	116,788	7,673
INCOME TAX PROVISION (BENEFIT)									(3,585)	(3,649)	(6,646)
Net income (loss)									(464,361)	120,437	14,319
Guarantor Subsidiaries
REVENUES:
Oil and natural gas sales									592	1,138	1,233
Total revenues									592	1,138	1,233
EXPENSES:
Lease operating expense									45	53	50
Production and property taxes									3	18	100
Transportation expense									36	13	12
Depletion, depreciation and amortization									105	105	105
Accretion of asset retirement obligations									136	127	117
General and administrative, net of amounts capitalized									1	1	1
Total expenses									326	317	385
Income (loss) from operations									266	821	848
FINANCING COSTS AND OTHER:
Income (loss) before income taxes									266	821	848
INCOME TAX PROVISION (BENEFIT)									102	312	322
Net income (loss)									164	509	526
Non-Guarantor Subsidiary
REVENUES:
Other									7,149	7,872	16,073
Total revenues									7,149	7,872	16,073
EXPENSES:
Lease operating expense									3,250	3,455	2,592
Production and property taxes									248	256	205
Depletion, depreciation and amortization									837	833	796
Accretion of asset retirement obligations									19	43	41
General and administrative, net of amounts capitalized									492	542	525
Total expenses									4,846	5,129	4,159
Income (loss) from operations									2,303	2,743	11,914
FINANCING COSTS AND OTHER:
Interest expense, net									(6,864)	(6,039)	(4,727)
Total financing costs and other									(6,864)	(6,039)	(4,727)
Income (loss) before income taxes									9,167	8,782	16,641
INCOME TAX PROVISION (BENEFIT)									3,483	3,337	6,324
Net income (loss)									$ 5,684	$ 5,445	$ 10,317

GUARANTOR FINANCIAL INFORMATI67

GUARANTOR FINANCIAL INFORMATION - Cash flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$ 9,428	$ 31,199	$ 84,834
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties	(29,405)	(87,660)	(101,995)
Acquisitions of oil and natural gas properties	(21)	(38)	(45)
Expenditures for property and equipment and other	(193)	(647)	(2,490)
Proceeds provided by sale of oil and natural gas properties	1,844	196,534	101,077
Net cash (used in) investing activities	(27,775)	108,189	(3,453)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	340,000	182,000	705,025
Principal payments on long-term debt	(155,000)	(322,000)	(781,905)
Payments for deferred loan costs		(1,068)	(7,491)
Premium to retire debt			(37,091)
Going private share repurchase costs			(9)
Debt issuance costs	(12,423)
Increase in restricted cash	(79,589)
Denver Parent Corporation capital contribution			3,108
Net cash provided by (used in) financing activities	92,988	(141,068)	(118,363)
Net (decrease) increase in cash and cash equivalents	74,641	(1,680)	(36,982)
Cash and cash equivalents, beginning of period	15,656	17,336	54,318
Cash and cash equivalents, end of period	90,297	15,656	17,336
Venoco, Inc.
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	9,497	51,214	89,517
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties	(29,405)	(87,660)	(101,995)
Acquisitions of oil and natural gas properties	(21)	(38)	(45)
Expenditures for property and equipment and other	(193)	(647)	(2,490)
Proceeds provided by sale of oil and natural gas properties	1,844	196,534	101,077
Net cash (used in) investing activities	(27,775)	108,189	(3,453)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	340,000	182,000	456,900
Principal payments on long-term debt	(155,000)	(322,000)	(716,900)
Payments for deferred loan costs		(871)	(1,260)
Premium to retire debt			(20,370)
Going private share repurchase costs			(9)
Debt issuance costs	(12,423)
Increase in restricted cash	(79,589)
Dividend paid to Denver Parent Corporation		(3,905)	(15,800)
Denver Parent Corporation capital contribution			158,385
Net cash provided by (used in) financing activities	92,988	(144,776)	(139,054)
Net (decrease) increase in cash and cash equivalents	74,710	14,627	(52,990)
Cash and cash equivalents, beginning of period	15,455	828	53,818
Cash and cash equivalents, end of period	90,165	15,455	828
Venoco, Inc
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	(1,346)	40,131	71,587
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties	(29,327)	(87,590)	(101,845)
Acquisitions of oil and natural gas properties	(21)	(38)	(45)
Expenditures for property and equipment and other	(193)	(647)	(2,490)
Proceeds provided by sale of oil and natural gas properties	1,844	196,534	101,077
Net cash (used in) investing activities	(27,697)	108,259	(3,303)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from (repayments of) intercompany borrowings	10,765	11,013	17,780
Proceeds from long-term debt	340,000	182,000	456,900
Principal payments on long-term debt	(155,000)	(322,000)	(716,900)
Payments for deferred loan costs		(871)	(1,260)
Premium to retire debt			(20,370)
Going private share repurchase costs			(9)
Debt issuance costs	(12,423)
Increase in restricted cash	(79,589)
Dividend paid to Denver Parent Corporation		(3,905)	(15,800)
Denver Parent Corporation capital contribution			158,385
Net cash provided by (used in) financing activities	103,753	(133,763)	(121,274)
Net (decrease) increase in cash and cash equivalents	74,710	14,627	(52,990)
Cash and cash equivalents, beginning of period	15,455	828	53,818
Cash and cash equivalents, end of period	90,165	15,455	828
Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	530	1,110	1,095
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties	(75)	7	10
Net cash (used in) investing activities	(75)	7	10
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from (repayments of) intercompany borrowings	(455)	(1,117)	(1,105)
Net cash provided by (used in) financing activities	(455)	(1,117)	(1,105)
Non-Guarantor Subsidiary
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	10,313	9,973	16,835
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and natural gas properties	(3)	(77)	(160)
Net cash (used in) investing activities	(3)	(77)	(160)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from (repayments of) intercompany borrowings	(10,310)	(9,896)	(16,675)
Net cash provided by (used in) financing activities	$ (10,310)	$ (9,896)	$ (16,675)