UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑K

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

For the fiscal year ended December 31, 2015

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

For the transition period from                  to

Commission file numbers:

Denver Parent Corporation 333‑191602

Venoco, Inc. 001‑33152

DENVER PARENT CORPORATION

VENOCO, INC.

(Exact Name of Registrant as Specified in its Charter)

(303) 626‑8300

(Registrant’s telephone number, including area code)

Securities Registered Pursuant to Section 12(b) of the Act:

Securities Registered Pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well‑known seasoned issuer, as defined in Rule 405 of the Securities Act.

Denver Parent Corporation Yes ☐  No ☒  Venoco, Inc. Yes ☐  No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

Denver Parent Corporation Yes ☒  No ☐  Venoco, Inc. Yes ☒  No ☐

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

Denver Parent Corporation Yes ☐  No ☒  Venoco, Inc. Yes ☐  No ☒

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S‑T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Denver Parent Corporation Yes ☐  No ☒  Venoco, Inc. Yes ☐  No ☒

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S‑K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10‑K or any amendment to this Form 10‑K. Denver Parent Corporation ☒  Venoco, Inc. ☒

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b‑2 of the Exchange Act). Denver Parent Corporation Yes ☐   No ☒  Venoco, Inc. Yes ☐  No ☒

All of the registrants’ common equity was held by affiliates on December 31, 2015.  As of June 3, 2016, there were 30,297,459 shares of common stock of Denver Parent Corporation and 29,936,378 shares of common stock of Venoco, Inc. outstanding.

Explanatory Note

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

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

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

VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION AND

SUBSIDIARIES 2015

ANNUAL REPORT ON FORM 10‑K

TABLE OF CONTENTS

FORWARD‑LOOKING STATEMENTS

This report on Form 10‑K contains certain forward‑looking statements. The use of any statements containing the words “anticipate,” “intend,” “believe,” “estimate,” “project,” “expect,” “plan,” “should” or similar expressions are intended to identify such statements. Forward‑looking statements included in this report relate to, among other things, expected future production, expenses and cash flows, the nature, timing and results of capital expenditure projects, amounts of future capital expenditures, our future debt levels and liquidity, our bankruptcy proceedings and the effect of those proceedings on our future operations, Venoco’s receipt of governmental consents, approvals and permits and the timing of such receipt and future transactions. The expectations reflected in such forward‑looking statements may prove to be incorrect. Disclosure of important factors that could cause actual results to differ materially from our expectations, or cautionary statements, are included under the heading “Risk Factors” in this report. Certain cautionary statements are also included elsewhere in this report, including, without limitation, in conjunction with the forward‑looking statements. All forward‑looking statements speak only as of the date made. All subsequent written and oral forward‑looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements. We undertake no obligation to update any forward‑looking statement. Factors that could cause actual results to differ materially from our expectations include, among others, those factors referenced in the “Risk Factors” section of this report and such things as:

GLOSSARY OF TECHNICAL TERMS

PART I

ITEM 1. AND ITEM 2.  Business and Properties

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. Since our founding in 1992, our core areas of focus have been offshore and onshore California. Our principal producing properties are heavily oil‑weighted and are located both onshore and offshore Southern California. These properties are characterized by long reserve lives, predictable production profiles and substantial opportunities for further exploitation and development. Additionally, we hold a 22.45% reversionary interest in certain properties in the Hastings Complex near Houston, Texas, where Denbury Resources, Inc., or Denbury, is currently performing an extensive CO₂ flood.

Bankruptcy Proceedings under Chapter 11

On March 18, 2016 (the “Petition Date”), the Company filed voluntary petitions seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware (In re Venoco, et al., Case No. 16-10655-KG) (the “Bankruptcy Court”). 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 and the Chapter 11 Subsidiaries 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, 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 cases, all transactions outside the ordinary course of our business require the prior approval of the Bankruptcy Court. As a result of the automatic stay, which became effective upon the commencement of the Chapter 11 cases, 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 are stayed. 

On April 11, 2016, the Company filed with the Bankruptcy Court a joint plan of reorganization (the “Plan”), which is supported by 100% of the senior secured notes and approximately 70% of the unsecured notes issued by Venoco (the “Restructuring Support Parties”). The Plan is subject to confirmation by the Bankruptcy Court. If the Plan is ultimately approved by the Bankruptcy Court, the Company and the Chapter 11 Subsidiaries 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 from bankruptcy, subject to dilution by any shares issuable upon exercise of new warrants to be issued under the Plan.

A hearing to consider approval of the disclosure statement with respect to the Plan is scheduled on May 16, 2016 in the Bankruptcy Court. A confirmation hearing on the Plan is scheduled on July 13, 2016 in the Bankruptcy Court.

For a further description of these matters, see Note 1 to our Consolidated Financial Statements. 

As a consequence of depressed oil prices, pipeline shut-in and our limited liquidity (See “2016 Liquidity and Capital Resources” in Management’s Discussion and Analysis in this report), as disclosed in our Bankruptcy Court filings, the Company’s current $20.4 million capital budget for 2016 is significantly reduced from 2015 levels.

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 proceedings as described in Item 1A, “Risk Factors.” As a result of these risks and uncertainties, our assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this Annual Report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.

Overview

According to a reserve report prepared by DeGolyer & MacNaughton, we had proved reserves of approximately 13.1 MMBOE as of December 31, 2015, based on Venoco’s SEC adjusted weighted average prices of $38.32 per Bbl for oil and $2.96 per MMBtu for natural gas. As of that date, 94% of our proved reserves were oil, and as a result of the uncertainty surrounding our ability to continue as a going concern, 100% were proved developed. The PV‑10 of our net reserves was approximately $17.4 million at year end. Our definition of PV‑10, and a reconciliation of a standardized measure of discounted future net cash flows to PV‑10, is set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operation—PV‑10.” Our average net production in 2015 was 3,980 BOE/d.

The following table summarizes certain information concerning our production in 2015.

Going Private Transaction

In January 2012, Venoco entered into a merger agreement with Timothy Marquez, currently DPC’s Chief Executive Officer and Venoco’s Executive Chairman, and certain affiliates of Mr. Marquez, including DPC. Mr. Marquez then beneficially owned approximately 50% of Venoco’s common stock. Pursuant to the merger agreement, DPC acquired all of Venoco’s common stock not beneficially owned by Mr. Marquez for $12.50 per share in cash in a transaction that was completed in October 2012. We refer to this transaction as the going private transaction. DPC is privately‑held and, as a result of the going private transaction, Venoco’s common stock ceased trading on the New York Stock Exchange and was deregistered under the Securities Exchange Act of 1934 (the “Exchange Act”). However, the Company has outstanding notes, and the indentures governing the notes require each company to file reports with the SEC as if it was a reporting company under SEC rules. Venoco and DPC are filing this combined report to satisfy those reporting requirements. See “Explanatory Note” immediately preceding Part I of this report.

Description of Properties

Southern California—Legacy Fields

South Ellwood Field.  The South Ellwood field is located in state waters approximately two miles offshore California in the Santa Barbara channel. We conduct our operations in the field from platform Holly and own related onshore processing facilities. We acquired our interest in the field from Mobil Oil Corporation in 1997. Since that time, we have made numerous operational enhancements to the field, including redrills, sidetracks and reworks of existing wells and upgrades at the platform and the supporting infrastructure. We operate the field and have a 100% working interest.

The South Ellwood field is approximately seven miles long and is part of a regional east‑west trend of similar geologic structures running along the northern flank of the Santa Barbara channel and extending to the Ventura basin. This trend encompasses several fields that, over their respective lifetimes, are each expected to produce over 100 million barrels of oil, according to the California Division of Oil, Gas, and Geothermal Resources. The Monterey shale formation is the primary oil reservoir in the field, producing sour oil with a gravity of approximately 24 degrees. As of December 31, 2015, there were 22 producing wells and four injection wells in the field.

Our processing and transportation facilities at South Ellwood include a common carrier pipeline, the Ellwood Onshore Facility (“EOF”) and a pier. We conduct three‑ phase separation on the platform where an  oil/water emulsion and natural gas are transported by separate pipelines to the EOF for further processing. After separation, the oil is transported to a third‑party refinery via pipeline, including a common carrier pipeline operated by our subsidiary Ellwood Pipeline, Inc and a common carrier pipeline operated by Plains All-American Pipeline Company (“Plains”). Natural gas produced at the field is processed at the onshore facility and transported by common carrier pipeline.

On May 19, 2015, the common carrier pipeline operated by Plains ruptured, resulting in a spill near Refugio Beach State Park.  The affected pipeline, in Santa Barbara County, is currently inoperable due to the spill and related ongoing repairs.  As a result, we have been forced to halt production activities at Platform Holly in response to the incident.  Although the ruptured section of the line has been repaired, Plains has stated that until the required metallurgical and root cause analyses are completed, it will be unable to address the timing of returning the pipeline to service.  At the time of this filing, we do not anticipate returning Platform Holly to service in 2016.

Production from Platform Holly accounted for approximately half of the Company’s total production and therefore the shut-down has had a significant impact on our operating cash flows.  We have taken measures to reduce the expenses associated with maintaining the platform and the Ellwood on-shore facility while we are not producing, including obtaining permits from the State of California to reduce the number of employees required to operate.  However, there are still significant operating expenses associated with the platform and the on-shore facility that we must incur while production is shut in.

In April 2014 we submitted an application to adjust the lease line at the South Ellwood field, and that application was deemed complete by the California State Lands Commission (CSLC) in June 2014. If made, the adjustment could

significantly increase the reserves associated with the field. Subsequent development of the adjusted lease area can be accomplished using our existing facilities and infrastructure. Our application is subject to review by the CSLC under the California Environmental Quality Act, which requires an environmental impact report. In May 2015 CSLC initiated efforts relating to the environmental impact review (“EIR”) and related report as required by CEQA.  The scope of the EIR includes evaluating major environmental issues associated with the adjustment such as hazardous materials and risk of upset, air quality, greenhouse gases and a number of other issues, as well as a number of project alternatives.  We received a draft of the EIR in the first quarter 2016. The draft is currently under review.  Our application may not be granted on the terms we request or at all.

Santa Clara Federal Unit.  The Santa Clara Federal Unit is located in federal waters approximately ten miles offshore in the Santa Barbara channel near Oxnard, California. Our operations in the unit are conducted from two platforms, platform Gail in the Sockeye field and platform Grace in the Santa Clara field. We acquired our interest in the unit and the associated facilities from Chevron in February 1999. We operate the unit and have a 100% working interest.

The Sockeye field structure is a northwest/southeast trending anticline bounded to the north and south by fault systems. The field produces from multiple stacked reservoirs ranging from the Monterey shale, at about 4,000 feet, to the Middle Sespe at approximately 7,000 feet. Other formations include the Upper Topanga, Lower Topanga and Juncal. As of December 31, 2015, there were 26 producing wells and 5 injection wells in the field. The oil produced from the Monterey shale and Upper Topanga is sour with gravities ranging from 12 to 17 degrees. The Lower Topanga and Sespe horizons produce sweet crude with gravities of 27 to 32 degrees. Chevron shut‑in production at platform Grace in the Santa Clara field in 1997. We primarily use the platform as a launching and receiving facility for pipeline cleaning devices and as an interconnecting pipeline to transport oil and natural gas produced from platform Gail to our onshore plant in Carpinteria, California. In 2011, however, we returned one well to production at platform Grace. Both platforms are self‑sufficient, with all production, processing and power generation operations conducted offshore.

Dos Cuadras Field.  The Dos Cuadras field is located in federal waters approximately five miles offshore California in the Santa Barbara channel. We acquired our 25% non‑operated working interest in three platforms in the western two‑thirds of the field from Chevron in February 1999. We have working interests ranging from approximately 17.5% to 25% in the associated onshore facility and pipelines. The field is operated by an unaffiliated third party. As of December 31, 2015, there were 86 producing wells and 22 injection wells in the field.

Beverly Hills West Field.  The Beverly Hills West field is located in Beverly Hills, California. All drilling and production operations at the field are conducted from a 0.6 acre surface location adjacent to the campus of Beverly Hills high school. We acquired our interest in the field in 1995. We operate the field and have a 100% working interest. As of December 31, 2015, there were 13 producing wells and three injection wells in the field, which produce oil with a gravity of approximately 26 degrees. The lease under which we operate the field expires on December 31, 2016. We have commenced the process to permit the shutdown of the facility and are proposing to continue producing oil and gas during the initial stages of the process.

Southern California—Onshore Monterey Shale

We have developed considerable knowledge of the Monterey shale formation through our work at the offshore South Ellwood and Sockeye (Santa Clara Unit) fields and believe the formation holds exploration opportunities onshore. As of December 31, 2015, our onshore Monterey shale acreage position totaled approximately 18,990 net acres and is located primarily in two basins: Salinas Valley and San Joaquin.

Texas

In February 2009, we sold certain properties in the Hastings Complex near Houston, Texas to Denbury for approximately $247.7 million (including a $50 million option payment made prior to closing), but we retained an interest in the properties relating to a CO₂ enhanced recovery project to be pursued by Denbury. As part of the plan, Denbury is responsible for providing the necessary CO₂. We have the right to back‑in to a working interest of approximately 22.45% in the Hastings Complex after Denbury recoups (i) its operating costs relating to the project and a portion of the purchase price and (ii) 130% of its capital expenditures made on the project. The agreement also establishes an area of mutual

interest with respect to us and Denbury in specified areas adjacent to the properties. The success of the CO₂ enhanced recovery project will be subject to numerous risks and uncertainties, including those relating to the geologic suitability of the properties for such a project and the availability of an economic and reliable supply of CO₂. Denbury commenced injecting CO₂ at the complex in December 2010 and began production in January 2012. Denbury has informed us that production from the complex averaged approximately 5,082 BOE/d for the full year 2015 and 4,811 BOE/d in the fourth quarter of 2015.

Oil and Natural Gas Reserves

The following table sets forth our net proved reserves as of the dates indicated. Our reserves as of December 31, 2014 and 2015 are set forth in reserve reports prepared by DeGolyer & MacNaughton. DeGolyer & MacNaughton reviews production histories and other geologic, economic, ownership and engineering data related to our properties in arriving at their reserve estimates. Proved reserves as of each date indicated reflect all acquisitions and dispositions completed as of that date. A report of DeGolyer & MacNaughton regarding its estimates of our proved reserves as of December 31, 2015 has been filed as Exhibit 99.1 to this report.

Changes in Proved Reserves

Our net proved reserves of 13.1 MMBOE as of December 31, 2015 decreased 67% from 40.4 MMBOE as of December 31, 2014. Our estimated oil and natural gas reserves were principally affected by the following during 2015:

Controls Over Reserve Report Preparation, Technical Qualifications and Technologies Used

Our year‑end reserve report is prepared by DeGolyer & MacNaughton in accordance with guidelines established by the SEC. Reserve definitions comply with the definitions provided by Regulation S‑X of the SEC. DeGolyer & MacNaughton prepares the reserve report based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geoscience and engineering data, and other information we provide to them. This information is reviewed by knowledgeable members of our company for accuracy and completeness prior to submission to DeGolyer & MacNaughton. Upon analysis and evaluation of the data, DeGolyer & MacNaughton issues a preliminary appraisal report of our reserves. The preliminary appraisal report and changes in our reserves are reviewed by our Reserves Manager, relevant Reservoir Engineers and Mark DePuy, our Chief Executive Officer, for completeness of the data presented, reasonableness of the results obtained and compliance with the reserves definitions in Regulation S‑X. Once all questions have been addressed, DeGolyer & MacNaughton issues the final appraisal report, reflecting its conclusions.

A letter which identifies the professional qualifications of the individual at DeGolyer & MacNaughton who was responsible for overseeing the preparation of our reserve estimates as of December 31, 2015 has been filed as an addendum to Exhibit 99.1 to this report and is incorporated by reference herein.

Internally, Ms. Gale Wright is responsible for overseeing our reserves process. Ms. Wright joined Venoco in 2006 as part of the Reserves and Acquisitions & Development group. In 2008, Ms. Wright was promoted to Reserves Manager responsible for all corporate Reserves Reporting. She assists the financial team with project forecasting, planning and modeling. Ms. Wright has over 30 years of industry experience in various operational and business development roles in the Rockies, Gulf Coast, Permian Basin and California beginning with 10 years at Chevron followed by other several large companies such as Conoco Phillips and Enron.

A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetrics, material balance, advance production type curve matching, petrophysics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

Production, Prices, Costs and Balance Sheet Information

The following table sets forth certain information regarding our net production volumes, average sales prices realized, and certain expenses associated with sales of oil and natural gas for the periods indicated. We urge you to read this information in conjunction with the information contained in our financial statements and related notes included elsewhere in this report. No pro forma adjustments have been made for acquisitions and divestitures of oil and natural gas properties, which will affect the comparability of the data below. The information set forth below is not necessarily indicative of future results.

Drilling Activity

The following table sets forth information with respect to development and exploration wells we completed from January 1, 2013 through December 31, 2015. The number of gross wells is the total number of wells we participated in, regardless of our ownership interest in the wells. Fluid injection wells for waterflood and other enhanced recovery projects are not included as gross or net wells.

The information above should not be considered indicative of future drilling performance, nor should it be assumed that there is any correlation between the number of productive wells drilled and the amount of oil and natural gas that may ultimately be recovered.

Oil and Natural Gas Wells

The following table details our working interests in producing wells as of December 31, 2015. A well with multiple completions in the same bore hole is considered one well. Wells are classified as oil or natural gas wells according to the predominant production stream, except that a well with multiple completions is considered an oil well if one or more is an oil completion.

Acreage

The following table summarizes our estimated developed and undeveloped leasehold acreage as of December 31, 2015. We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest.

Risk and Insurance Program

Our operations are subject to all the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including the risk of well blowouts, oil spills and other adverse events. We could be held responsible for injuries suffered by third parties, contamination, property damage or other losses resulting from these types of events. In addition, we have generally agreed to indemnify our drilling rig contractors against certain of these types of losses. Because of these risks, we maintain insurance against some, but not all, of the potential risks affecting our operations and in coverage amounts and deductible levels that we believe to be economic. Our insurance program is designed to provide us with what we believe to be an economically appropriate level of financial protection from significant unfavorable losses resulting from damages to, or the loss of, physical assets or loss of human life or liability claims of third parties, attributed to certain assets and including such occurrences as well blowouts and resulting oil spills. We regularly review our risks of loss and the cost and availability of insurance and consider the need to revise our insurance program accordingly. Our insurance coverage includes deductibles which must be met prior to recovery. Additionally, our insurance is subject to exclusions and limitations and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.

In general, our current insurance policies covering a blowout or other insurable incident resulting in damage to one of our offshore oil and gas wells provide up to $90 million of well control, pollution cleanup and consequential damages coverage and $300 million of third party liability coverage for additional pollution cleanup and consequential damages, which also covers personal injury and death.

If a well blowout, spill or similar event occurs that is not covered by insurance, it could have a material adverse impact on our financial condition, results of operations and cash flows. See “Risk Factors—Our business involves significant operating risks that could adversely affect our production and could be expensive to remedy. We do not have insurance to cover all of the risks that we may face”.

Remediation Plans and Procedures

As required by regulations imposed by the Bureau of Safety and Environmental Enforcement (“BSEE”), we annually update our existing company oil‑spill response plan as required by regulations, we continue to maintain oil spill response equipment on the platforms, including oil spill containment boom and a boat for boom deployment, and have maintained oil‑spill financial assurance in connection with our offshore operations. Our oil‑spill response plan details

procedures for rapid response to spill events that may occur as a result of our operations. The plan calls for training personnel in spill response. Drills are conducted annually to measure and maintain the effectiveness of the plan, and plan or equipment improvements are made accordingly.

Also pursuant to BSEE regulations and similar regulations adopted by the California Department of Fish and Game’s Office of Oil Spill Prevention and Response, we continue to be a member of Clean Seas, LLC, or Clean Seas, a cooperative entity operated with other offshore operators to effectively respond to oil spills in the offshore region in which we operate. The purpose of Clean Seas is to act as a resource to its member companies by providing an inventory of state‑of‑the‑art oil spill response equipment, trained personnel, and expertise in the planning and execution of response techniques. Clean Seas’ Oil Spill Response Organization (OSRO) primarily consists of four oil spill response vessels and one oil spill response barge including all associated manpower, equipment and materials to satisfy federal, state, and local spill response requirements. Clean Seas also recruits and trains local fishermen to assist in oil recovery and the recovery of impacted wildlife. Clean Seas’ designated area of response, which encompasses all of our offshore operations, comprises the open oceans and coastline of the South Central Coast of California including Ventura, Santa Barbara, and San Luis Obispo Counties, and the Santa Barbara Channel Islands.

Title to Properties

We believe that we have satisfactory title to all of our material assets. Title to our properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating and debt agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry. However, we believe that none of these liens, restrictions, easements, burdens and encumbrances materially interfere with our use of those properties, in each case in the operation of our business as currently conducted. We believe that we have obtained sufficient right‑of‑way grants and permits from public authorities and private parties for us to operate our current business in all material respects as described in this report. As is customary in the oil and natural gas industry, we typically make minimal investigation of title at the time we acquire undeveloped properties. We make title investigations and receive title opinions of local counsel only before we commence drilling operations.

Marketing, Major Customers and Delivery Commitments

Markets for oil and natural gas are volatile and are subject to wide fluctuations depending on numerous factors beyond our control, including seasonality, economic conditions, foreign imports, political conditions in other energy producing countries, OPEC market actions, and domestic government regulations and policies. All of our production is sold to competing buyers, including large oil refining companies and independent marketers. In the year ended December 31, 2015, approximately 97% of our revenues were generated from sales to two purchasers: ConocoPhillips 66 (29%) and Tesoro Refining and Marketing Company (68%). Substantially all of our production is sold pursuant to agreements with pricing based on prevailing commodity prices, subject to adjustment for regional differentials and similar factors. We had no material delivery commitments as of May 13, 2016.

Competition

The oil and natural gas business is highly competitive with respect to the search for and acquisition of additional reserves and in the sale of oil and natural gas. Our competitors principally consist of major and intermediate sized integrated oil and natural gas companies, independent oil and natural gas companies and individual producers and operators. In particular, we compete for property acquisitions and for the equipment and labor required to operate and develop our properties. These competitors may be able to pay more for properties and may be able to define, evaluate, bid for and purchase a greater number of properties than we can. Ultimately, our future success will depend on our ability to develop or acquire additional reserves at costs that allow us to remain competitive.

Offices

We currently lease approximately 24,000 net square feet of office space in Denver, Colorado, where our principal office is located. The lease for the Denver office expires in 2024. We lease an additional 51,000 net square feet of office space in Carpinteria, California from 6267 Carpinteria Avenue, LLC. The lease for the Carpinteria office will expire in 2023. We also have leases for certain field offices which are insignificant on a quantitative basis. We believe that our office facilities are adequate for our current needs and that additional office space can be obtained if necessary.

Employees

As of December 31, 2015, we had approximately 162 full‑time employees, none of whom were party to collective bargaining arrangements.

Regulatory Environment

Our oil and natural gas exploration, production and transportation activities are subject to extensive regulation at the federal, state and local levels. These regulations relate to, among other things, environmental and land‑use matters, conservation, safety, pipeline use, drilling and spacing of wells, well stimulation, transportation, and forced pooling and protection of correlative rights among interest owners. The following is a summary of some key statutory and regulatory programs that affect our operations.

Environmental and Land Use Regulation

A wide variety of environmental and land use regulations apply to companies engaged in the production and sale of oil and natural gas. These regulations have been changed frequently in the past and, in general, these changes have imposed more stringent requirements that increase operating costs and/or require capital expenditures to remain in compliance. Failure to comply with these requirements can result in civil and/or criminal penalties and liability for non‑compliance, clean‑up costs and other environmental damages. It also is possible that unanticipated developments or changes in the law could require us to make environmental expenditures significantly greater than those we currently expect.

California Environmental Quality Act (“CEQA”).  CEQA is a California statute that requires consideration of the environmental impacts of proposed actions that may have a significant effect on the environment. CEQA requires the responsible governmental agency to prepare an environmental impact report that is made available for public comment. The responsible agency also is required to consider mitigation measures. The party requesting agency action bears the expense of the report.

Discharges to Waters.  The Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), and comparable state statutes impose permitting and regulatory restrictions and controls on the discharge of “pollutants,” including produced waters, sand, drilling fluids, drill cuttings and other substances related to the oil and natural gas industry into onshore, coastal, and offshore waters, and other regulated waters and wetlands. These controls generally have become more stringent over time, and it is possible that additional restrictions will be imposed in the future. Violation of the Clean Water Act and similar state regulatory programs can result in civil, criminal and administrative penalties for unauthorized discharges of oil, hazardous substances and other pollutants. They also can impose substantial liability for the costs of removal or remediation associated with such discharges.

The Clean Water Act also regulates stormwater discharges from industrial properties and construction sites, and requires separate permits and implementation of a Stormwater Pollution Prevention Plan (“SWPPP”) establishing best management practices, training, and periodic monitoring of covered activities. Certain operations also are required to develop and implement Spill Prevention, Control, and Countermeasure (“SPCC”) plans or facility response plans to address potential oil spills from certain above‑ground and underground storage tanks.

Oil Spill Regulation.  The Oil Pollution Act of 1990, as amended (“OPA”), amends and augments the Clean Water Act as it relates to oil spills, and imposes potentially unlimited liability on responsible parties without regard to

fault for the removal costs resulting from an offshore facility oil spill in federal waters. However, while the OPA limits liability for certain “damages” resulting from an oil spill, the Bureau of Ocean Energy Management (“BOEM”) announced in December 2014, that it was increasing that liability limit to $133.65 million from $75 million. Responsible parties under the OPA include owners and operators of onshore facilities and pipelines and lessees or permittees of offshore facilities. In addition, BOEM regulations require parties responsible for offshore facilities to provide financial assurance to cover potential OPA liabilities in the amount of $35 million, which can be increased to $150 million in some circumstances.

Regulations promulgated by the BSEE require oil‑spill response plans for offshore oil and natural gas operations, whether operating in state or federal waters. These regulations were designed to be consistent with OPA and other similar requirements. Under BSEE regulations, operators must join a cooperative that makes oil‑spill response equipment available to its members. The California Department of Fish and Wildlife’s Office of Oil Spill Prevention and Response (“OSPR”) has adopted oil‑spill prevention regulations that overlap with federal regulations. We have complied with these OPA, BSEE and OSPR requirements by adopting an offshore oil‑spill contingency plan and becoming a member of Clean Seas, LLC, a cooperative entity operated with other offshore operators to prevent and respond to oil spills in the offshore region in which we operate. See “—Remediation Plans and Procedures”.

Air Emissions.  Our operations are subject to local, state and federal regulations governing emissions of air pollutants. Local air‑quality districts are responsible for much of the regulation of air‑pollutant sources in California. California requires new and modified stationary sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally based permitting requirements. Because of the severity of ozone levels in portions of California, the state has the most severe restrictions on emissions of volatile organic compounds (“VOCs”) and nitrogen oxides (“NOX”) of any state. Producing wells, natural gas plants and electric generating facilities all generate VOCs and NOX. Some of our producing wells are in counties that are designated as non‑attainment for ozone and, therefore, potentially are subject to restrictive emission limitations and permitting requirements. California also operates a stringent program to control hazardous (toxic) air pollutants, and this program could require the installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits generally are resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could require us to forego construction, modification or operation of certain air‑emission sources. Air emissions from oil and natural gas operations also are regulated by oil and natural gas permitting agencies, including BSEE, the California State Lands Commission (“CSLC”), and other local agencies.

Additionally, effective June 4, 2013, an information gathering rule adopted by the South Coast Air Quality Management District (“SCAQMD”), Rule 1148.2, requires well operators of onshore wells subject to SCAQMD’s jurisdiction to notify SCAQMD before undertaking certain activities at wells, including hydraulic fracturing, and then to report information regarding chemical usage and operational data regarding those well activities. SCAQMD anticipates reviewing the information gathered under SCAQMD Rule 1148.2 and developing regulations if necessary to protect air quality. If SCAQMD develops regulations regarding well activities, including hydraulic fracturing, our operating costs could increase.

Waste Disposal.  We currently own or lease a number of properties that have been used for production of oil and natural gas for many years. Although we believe the prior owners and/or operators of those properties generally utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties we currently own or lease. State and federal laws applicable to oil and natural gas wastes have become more stringent. Under new laws, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed of or released by prior owners or operators) or to perform remedial well‑ plugging operations to prevent future, or mitigate existing, contamination.

We may generate wastes, including “solid” wastes and “hazardous” wastes that are subject to the federal Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. Although certain oil and natural gas exploration and production wastes currently are exempt from regulation as hazardous wastes under RCRA, the federal Environmental Protection Agency (“EPA”) has limited the disposal options for certain wastes

designated as hazardous wastes under RCRA. It is possible that certain wastes generated by our oil and natural gas operations that currently are exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes, and may therefore become subject to more rigorous and costly management, disposal and clean‑up requirements. State and federal oil and natural gas regulations also provide guidelines for the storage and disposal of solid wastes resulting from the production of oil and natural gas, both onshore and offshore.

Superfund.  Under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended, also known as CERCLA or the Superfund law, and similar state laws, responsibility for the entire cost of cleanup of a contaminated site, as well as natural resource damages, can be imposed upon current or former site owners or operators, or upon any party who released one or more designated “hazardous substances” at the site, regardless of the lawfulness of the original activities that led to the contamination. CERCLA also authorizes EPA and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. Although CERCLA generally excludes petroleum from the definition of hazardous substances, in the course of our operations we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of facilities at which hazardous substances have been released by previous owners or operators. We may be responsible under CERCLA for all or part of the costs of cleaning up facilities at which such substances have been released and for natural resource damages. We have not, to our knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their ownership or operation of those properties.

Abandonment, Decommissioning and Remediation Requirements.  Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production and transportation facilities and the environmental restoration of operations sites. BSEE regulations, coupled with applicable lease and permit requirements and each property’s specific development and production plan, prescribe the requirements for decommissioning our federally leased offshore facilities. CSLC and the California Department of Conservation, Division of Oil, Gas and Geothermal Resources (“DOGGR”) are the principal state agencies responsible for regulating the drilling, operation, maintenance and abandonment of all oil and natural gas wells in the state, whether onshore or offshore. BOEM regulations require federal leaseholders to post performance bonds. See “—Potentially Material Costs Associated with Environmental Regulation of Our Oil and Natural Gas Operations—Plugging and Abandonment Costs” for a discussion of our principal obligations relating to the abandonment and decommissioning of our facilities.

California Coastal Act.  The California Coastal Act regulates the conservation and development of California’s coastal resources. The California Coastal Commission (the “Coastal Commission”) works with local governments to make permit decisions for new developments in certain coastal areas and reviews local coastal programs, such as land‑use restrictions. The Coastal Commission also works with the OSPR to protect against and respond to coastal oil spills. The Coastal Commission has direct regulatory authority over offshore oil and natural gas development within the state’s three mile jurisdiction and has authority, through the Federal Coastal Zone Management Act, over federally permitted projects that affect the state’s coastal zone resources. We conduct activities that may be subject to the California Coastal Act and the jurisdiction of the Coastal Commission.

Marine Protected Areas (“MPAs”).  In 2000, President Clinton issued Executive Order 13158, which directs federal agencies to strengthen management, protection and conservation of existing MPAs and to establish new MPAs. The executive order requires federal agencies to avoid causing harm to MPAs through federally conducted, approved, or funded activities. The order also directs EPA to propose new regulations under its Clean Water Act authority to ensure protection of the marine environment. This order and related Clean Water Act regulations have the potential to adversely affect our operations by restricting areas in which we may engage in future exploration, development, and production operations and by causing us to incur increased expenses.

Naturally Occurring Radioactive Materials (“NORM”).  Our operations my generate wastes containing NORM. Certain oil and natural gas exploration and production activities can enhance the radioactivity of NORM. NORM primarily is regulated by state radiation control regulations. The Occupational Safety and Health Administration also has promulgated regulations addressing the handling and management of NORM. These regulations impose certain

requirements regarding worker protection, the treatment, storage, and disposal of NORM waste, the management of NORM containers, tanks, and waste piles, and certain restrictions on the uses of land with NORM contamination.

Well Stimulation Regulations.  We have on occasion in the past engaged in activities involving the use of hydraulic fracturing and other well‑stimulation methods, and could use them in the future. Hydraulic fracturing is a process that creates a fracture extending from the well bore in a rock formation to enable oil or natural gas to move more easily through the rock to a production well. Fractures typically are created through the injection of water, chemicals, and sand or other “proppants” into the rock formation. Several federal entities, including the EPA, recently have asserted potential regulatory authority over hydraulic fracturing, and the EPA is also conducting a nationwide study into the effects of hydraulic fracturing on drinking water. In June 2015, the EPA released a draft study report for peer review and comment. The draft report did not find evidence of widespread systemic impacts to drinking water, but did find a relatively small number of site-specific impacts. The EPA noted that these results could indicate that such effects are rare or that other limiting factors exist. A final report is expected in 2016. Moreover, in April 2015, the EPA proposed regulations under the CWA to impose pretreatment standards on wastewater discharges associated with hydraulic fracturing activities. Other federal agencies have examined and are continuing to examine hydraulic fracturing, including the U.S. Department of Energy, the U.S. Government Accountability Office and the White House Council for Environmental Quality. Federal agencies have also adopted or are considering additional regulation of hydraulic fracturing.  For example, on March 26, 2016, the U.S. Occupational Safety and Health Administration (“OSHA”) issued a final rule, with effective dates of 2018 and 2021 for the hydraulic fracturing industry, which imposes stricter standards for worker exposure to silica, including worker exposure to sand in hydraulic fracturing.

On March 20, 2015 the BLM released a final rule, which currently is stayed pending further litigation, that will regulate hydraulic fracturing on federal and Indian lands. The rule requires operators to: (i) submit detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, the depths of all usable water, estimated volume of fluid to be used, and estimated direction and length of fractures, to the BLM before hydraulically fracturing an existing well; (ii) design and implement a casing and cementing program that follows best practices and meets performance standards to protect and isolate “usable” water; (iii) monitor cementing operations during well construction; (iv) take remedial action if there are indications of inadequate cementing, and demonstrate to the BLM that the remedial action was successful; (v) perform a successful mechanical integrity test prior to the hydraulic fracturing operation; (vi) monitor annulus pressure during a hydraulic fracturing operation; (vii) manage recovered fluids in rigid enclosed, covered or netted and screened above‑ground storage tanks, with very limited exceptions that must be approved on a case‑by‑case basis; (viii) disclose the chemicals used to the BLM and the public, with limited exceptions for material demonstrated to be trade secrets; and (ix) provide documentation of all of the above actions to the BLM. In addition, Congress has considered, and may in the future consider, legislation that would amend the Safe Drinking Water Act to encompass hydraulic fracturing activities. Past proposed legislation would have required hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, including disclosure of chemicals used in the fracturing process, and meet plugging and abandonment requirements. If such legislation is adopted in the future, it would establish an additional level of regulation and impose additional costs on our operations.

EPA also has begun a Toxic Substances Control Act (“TSCA”) rulemaking, which will collect expansive information on the chemicals used in hydraulic fracturing fluid, as well as other health‑related data, from chemical manufacturers and processors. In addition, on January 7, 2015, several national environmental advocacy groups filed a lawsuit requesting that EPA grant their October 24, 2012 petition to add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under EPCRA’s Toxics Release Inventory (TRI) program. In an October 22, 2015 response, EPA granted the petition with respect to natural gas processing facilities and stated that it will propose adding those facilities to the scope of the TRI program.  However, EPA declined to propose adding any other oil and gas facilities to that program.

EPA also finalized major new Clean Air Act standards (New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants) applicable to hydraulically fractured natural gas wells in August 2012 known as “Quad O.” The standards require, among other things, use of reduced emission completions, or green completions, to reduce VOC emissions during hydraulically fractured natural gas well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers, and

dehydrators at gas well affected facilities. Following a legal challenge and several petitions for administrative reconsideration of the Quad O rules, EPA issued final amendments related to storage tanks, green completions, and other provisions of the rule in September 2013 and December 2014 respectively. Most key provisions in Quad O took effect in 2015. The rules associated with such standards are substantial and will likely increase future costs of our operations and will require us to make modifications to our operations or install new equipment.  In August 2015, the EPA proposed a package of new regulations under the CAA to reduce methane emissions from new and modified sources in the oil and gas sector. Concurrent with the proposed methane rules, the EPA also proposed a new rule for aggregating adjacent operational units into a single source for review and permitting and recommended guidelines for reducing volatile organic compound emissions from existing equipment. In October 2015, the EPA lowered the national ambient air quality standard (“NAAQS”) for ozone under the CAA from 75 parts per billion to 70 parts per billion, which is the same standard that has been in effect in California since 2005.

On September 20, 2013, California enacted Senate Bill 4, which requires the DOGGR to promulgate regulations regulating well‑stimulation operations, including hydraulic fracturing and certain acid stimulation treatments. On December 30, 2014, DOGGR released its final regulations, which went into effect on July 1, 2015. The final regulations require operators to obtain a permit prior to conducting well‑stimulation operations, notify DOGGR 72 hours prior to the start well‑stimulation treatments, and disclose various types of operational data, including the chemical composition of well‑stimulation fluids, which will be made available on a publicly accessible website. Operators also are required to hire an independent third party to notify every neighboring tenant and landowner within a prescribed distance at least 30 days prior to commencing well‑stimulation operations and to test well water and surface water suitable for drinking if requested by neighboring landowners. The regulations also require operators to evaluate and test the casing, tubing, and cement lining of the well borehole and related equipment to ensure that the well’s construction is more than adequate to withstand hydraulic fracturing operations. In addition, operators must ensure that all potentially productive zones, zones capable of over‑pressurizing the surface casing annulus, or corrosive zones are isolated and sealed to prevent vertical migration of gases or fluids behind the casing. The regulations also require operators to monitor and test the well during and after hydraulic fracturing operations to verify that no well failure has occurred. Operators also are required to monitor the California Integrated Seismic Network during and after hydraulic fracturing to determine if any earthquakes of magnitude 2.7 or greater occur within a specified area around the well. If such an earthquake occurs, further hydraulic fracturing in the area is suspended until authorized by DOGGR. Our current operations do not fall within the scope of Senate Bill 4 or the interim or final regulations. However, we will continue to monitor regulatory developments in this area.

Under Senate Bill 4, the state completed an environmental impact report (EIR) analyzing the effects of hydraulic fracturing statewide, on July 1, 2015. While the final EIR concludes that hydraulic fracturing has the potential to cause “significant and unavoidable impacts to aesthetics, air quality, biological resources, cultural resources, geology, soils and mineral resources, greenhouse gas emissions, land use planning, risk of upset/public and worker safety, and transportation and traffic,” it notes that all of these risks can be mitigated or prevented. In addition, the draft EIR concludes that hydraulic fracturing is the “Environmentally Superior Alternative” because limiting or prohibiting hydraulic fracturing would require greater levels of imported oil and gas resources, which would pose social, political, and economic consequences at the state and national scales.

Also, some states have adopted, and other states are considering adopting, requirements that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. For example, several states require the well‑by‑well public disclosure of all the constituent chemicals, compounds and water volume contained in fluids used for hydraulic fracturing. In addition, many states also require specific construction and testing requirements for wells that will be hydraulically fractured.

Various counties and municipalities around the country have passed laws restricting or prohibiting hydraulic fracturing. Our operations currently are not impacted by such laws. However, there is a risk that our operations could be adversely impacted by such laws in the future, especially since our operations are located in California, which historically has been at the forefront of environmental regulation. We will continue to monitor developments in this area.

Greenhouse Gas Regulation.  Recent and future environmental regulations, including additional federal and state restrictions on greenhouse gas (“GHG”) emissions passed in response to climate change concerns, may increase our

operating costs and reduce the demand for the oil and natural gas we produce. EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allowed EPA to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. As a result, EPA has begun to implement GHG‑related reporting and permitting rules, with which we are complying. In June 2014, however, the United States Supreme Court invalidated a portion of EPA’s GHG program in the case Utility Air Regulatory Group v. EPA (“UARG”). Specifically, under the Supreme Court’s UARG opinion, sources subject to the federal Title V and/or the Prevention of Significant Deterioration (“PSD”) programs because of emissions of non‑GHG pollutants may still be subject to GHG permitting, including requirements to install Best Available Control Technology (“BACT”). Sources that would be subject to Title V or PSD because of GHG emissions only, however, are no longer subject to GHG permitting requirements, including GHG BACT requirements. Upon remand, EPA currently is considering how to implement the Court’s decision.

On May 12, 2016, the EPA announced its final regulations that set methane emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities as part of an effort to reduce methane emissions from the oil and natural gas sector by 40 to 45 percent from 2012 levels by 2025. Under the rule, oil and gas companies will have to find and repair leaks, capture gas from the completion of fracked wells, limit emissions from new and modified pneumatic pumps, and limit emissions from several types of equipment used at gas transmission compressor stations, including compressors and pneumatic controllers. The California Air Resources Board (“CARB”) also is working on a rulemaking to reduce methane emissions from oil and gas production, processing, storage, and well stimulation (including hydraulic fracturing). CARB has held a series of workshops concerning the draft regulations, which include additional control, monitoring, recordkeeping, and reporting requirements focused on fugitive methane emissions for much of the oil and natural gas industry. In addition, on March 10, 2016, EPA announced that it will begin a formal process under CAA § 111(d) to require companies operating existing oil and gas sources to provide information to assist EPA in developing comprehensive regulations to reduce methane emissions. EPA will send Information Collection Requests (ICRs) to operators to gather information on existing sources of methane emissions, technologies to reduce those emissions, and the costs of those technologies in the production, gathering, processing, and transmission and storage segments of the oil and gas sector.

The U.S. Congress has considered and may in the future consider “cap and trade” legislation that would establish an economy‑wide cap on GHG emissions in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. On September 27, 2006, California’s governor signed into law Assembly Bill (AB) 32, known as the “California Global Warming Solutions Act of 2006,” which established a statewide cap on GHGs designed to reduce the state’s GHG emissions to 1990 levels by 2020 and establishes a “cap and trade” program. The California Air Resources Board adopted GHG regulations that went into effect on January 1, 2012, and the enforceable compliance obligations began on January 1, 2013. These regulations do not directly impact our operations as the first phase includes major industrial sources and utilities, while the second phase, which started in 2015, addresses distributors of transportation fuels, natural gas, and other fuels. We will continue to monitor the implementation of these regulations through industry trade groups and other organizations in which we are a member. Our current operations are subject to the reporting requirements of these regulations; however, our operations are not subject to current California cap and trade regulations.

Other Environmental Regulation.  Our leases in federal waters on the Outer Continental Shelf are administered by BOEM and BSEE and require compliance with detailed BOEM and BSEE regulations and orders. Under certain circumstances, BOEM or BSEE may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations.

Our offshore leases in state waters or “tidelands” (within three miles of the coastline) are administered by the state of California and require compliance with certain CSLC and DOGGR regulations. CSLC serves as the lessor of our state offshore leases and is charged with overseeing leasing, exploration, development and environmental protection of state tidelands.

Commencing with the Cunningham Shell Act of 1955, California has enacted several pieces of legislation that withhold state tidelands from oil and natural gas leasing. The Cunningham Shell Act protects an area of tidelands offshore Santa Barbara County that stretches west from Summerland Bay to Coal Oil Point, and includes waters offshore

the unincorporated area of Montecito, the City of Santa Barbara and the University of California at Santa Barbara. It also protects the state tidelands around the islands of Anacapa, Santa Cruz, Santa Rosa and San Miguel. In 1994, California enacted the California Sanctuary Act which, with three exceptions, prohibits leasing of any state tidelands for oil and natural gas development. Oil and natural gas leases in effect as of January 1, 1995 are unaffected by this legislation until such leases revert back to the state, at which time they will become part of the California Coastal Sanctuary. This legislation does not restrict our existing state offshore leases or our current or planned future operations.

Other environmental protection statutes that may impact our operations include the Marine Mammal Protection Act, the Marine Life Protection Act, the Marine Protection, Research, and Sanctuaries Act of 1972, the Endangered Species Act, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act.

Potentially Material Costs Associated with Environmental Regulation of Our Oil and Natural Gas Operations

Significant potential costs relating to environmental and land‑use regulations associated with our existing properties and operations include those relating to: (i) plugging and abandonment of facilities; (ii) clean‑up costs and damages due to spills or other releases; and (iii) penalties imposed for spills, releases or non‑compliance with applicable laws and regulations. As is customary in the oil and natural gas industry, we typically have contractually assumed, and may assume in the future, obligations relating to plugging and abandonment, clean‑up and other environmental costs in connection with our acquisition of operating interests in various fields, and these costs can be significant.

Plugging and Abandonment Costs.  Our operations, and in particular our offshore platforms and related facilities, are subject to stringent abandonment and closure requirements imposed by BSEE and the state of California. With respect to the Santa Clara Federal Unit, Chevron retained most of the abandonment obligations relating to the platforms and facilities when it sold the fields to us in 1999. We are responsible for abandonment costs relating to the wells and to any expansions or modifications we made following our acquisition of the fields. We also agreed to assume from Chevron all abandonment obligations associated with its 25% interest in the infrastructure (but not the wells) in the Dos Cuadras field. We agreed to assume all of the abandonment costs relating to the operations, including platform Holly, in the South Ellwood field when we purchased it from Mobil Oil Corporation in 1997.

As described in the notes to our financial statements, we have estimated the present value of our aggregate asset retirement obligations to be $33.3 million as of December 31, 2015. This figure reflects the expected future costs associated with site reclamation, facilities dismantlement and plugging and abandonment of wells. The discount rates used to calculate the present value varied depending on the estimated timing of the obligation and the risk profile of the Company at the time of the estimate. Actual costs may differ from our estimates. Our financial statements do not reflect any liabilities relating to other environmental obligations.

Under a variety of applicable laws and regulations, including CERCLA, RCRA and BSEE regulations, we could in some circumstances be held responsible for abandonment and clean‑up costs relating to our operations, both onshore and offshore, notwithstanding contractual arrangements that assign responsibility for those costs to other parties.

Clean‑up Costs.  Certain of our facilities have known environmental contamination for which we will be responsible for the associated clean‑up efforts, subject to our right to be indemnified by third parties in some cases. The regulators generally have not yet determined the applicable clean‑up requirements associated with the facilities. However, we expect that we will be permitted to defer remedial actions until we cease operations at the relevant facilities. As the clean‑up is expected to be performed at the end of the useful life of the relevant facilities, we have included estimates for the cost of the clean‑up in our asset retirement obligations reflected in our financial statements.

Penalties for Non‑Compliance.  We believe that our operations are in material compliance with all applicable oil and natural gas, safety, environmental and land‑use laws and regulations. However, from time to time we receive notices of noncompliance with Clean Air Act and other requirements from relevant regulatory agencies. We received a number of minor notices of violation (“NOVs”) from regulatory agencies in 2015. We do not expect to incur significant penalties with respect to any outstanding NOV. See “Legal Proceedings.”

Other Regulation

The pipelines we use to gather and transport our oil and natural gas are subject to regulation by the U.S. Department of Transportation (“DOT”) under the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), and the Pipeline Safety Act of 1992, which relate to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Under the Pipeline Safety Act, the Research and Special Programs Administration of DOT is authorized to require certain pipeline modifications as well as operational and maintenance changes. We believe our pipelines are in substantial compliance with HLPSA and the Pipeline Safety Act. Nonetheless, we could incur significant expenses if new or additional safety requirements are implemented.

The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act and the Natural Gas Policy Act. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open‑access, non‑ discriminatory basis.

The rates, terms, and conditions applicable to the interstate and intrastate transportation of oil by pipelines is regulated by, respectively, FERC under the Interstate Commerce Act and the California Public Utilities Commission under the California Public Resources Code.

The safety of our operations primarily is regulated by the BSEE, the CSLC, the Coast Guard and the Occupational Safety and Health Administration. We believe our facilities and operations are in substantial compliance with the applicable requirements of those agencies. In the event different or additional safety measures are required in the future, we could incur significant expenditures to meet those requirements.

Executive Officers of the Registrant

The following table sets forth certain information with respect to our executive officers as of December 31, 2015.

Timothy Marquez is DPC’s sole director and its CEO, having served in those roles since its formation in January 2012. He co‑founded Venoco in September 1992 and served as its CEO from its formation until June 2002. He founded Marquez Energy in 2002 and served as its CEO until we acquired it in March 2005. Mr. Marquez returned as Venoco’s Chairman, CEO and President in June 2004. He became Venoco’s Executive Chairman in August 2012. Mr. Marquez has a B.S. in petroleum engineering from the Colorado School of Mines. Mr. Marquez began his career with Unocal Corporation, where he worked for 13 years managing assets offshore California and in the North Sea and performing other managerial and engineering functions.

Mark DePuy became Venoco’s Chief Executive Officer in June of 2014. Mr. DePuy initially joined us in 2005 as Vice President of Northern Assets. The following year, he was named COO and oversaw our assets in Northern and Southern California, as well as numerous field operations in Texas. Mr. DePuy resigned as our COO in October 2008, after which he provided consulting services for us on coastal development projects in California. From March 2010 through November 2011, he served as CEO and President of Great Western Oil and Gas, a private oil and gas company with operations focused primarily in Colorado and North Dakota. Mr. DePuy rejoined us in the role of Senior Vice President, Business Development and Acquisitions in December 2011. He also has 27 years of experience in various operational, management and business planning functions with Unocal/Chevron in both the domestic and international operations. Mr. DePuy has an M.B.A. from the University of California, Los Angeles and a B.S. in petroleum engineering from the Colorado School of Mines.

Scott Pinsonnault became Venoco’s Chief Financial Officer in May of 2015 after serving as Interim CFO with the Company for nearly six months. Mr. Pinsonnault has 17 years of operating and financial experience, specifically in energy, oil and gas, and related industries. In his role as Managing Director at Opportune LLP’s Energy Practice, Mr. Pinsonnault’s experience includes work with diverse constituencies including public and private companies and their boards, equity sponsors, lenders, trusts and regulatory agencies. Mr. Pinsonnault’s strong financial background is backed up by five years of hands-on technical, geologic, operational, and engineering experience garnered while serving in various leadership roles at Deloitte, American Capital Limited, GE Financial Services and Quicksilver Resources.  Mr. Pinsonnault has and MBA from Tulane’s A.B. Freeman School of Business, an M.S. in Geology and Geophysics from Texas A&M and a B.S. from Saint Lawrence University.

Brian E. Donovan became General Counsel and Secretary in October of 2014. Mr. Donovan began his tenure with Venoco as Assistant General Counsel and Assistant Secretary in December of 2007 and has served as an integral part of the management team ever since. Prior to joining Venoco, he amassed over 20 years of legal experience with various subsidiaries of Peabody Energy, Inc. including Gold Fields Mining Corporation, Arid Operations, Inc., and Peabody Natural Gas, LLC. Mr. Donovan holds a Bachelor of Science degree in petroleum engineering from the Colorado School of Mines, a Juris Doctor degree from the University of Denver, and a Master of Laws degree in taxation from the University of Denver and is licensed to practice law in Colorado.

Michael Wracher became Venoco’s Senior Vice President of Southern California Operations in July 2015. He joined Venoco in 1998 and has held various roles of increasing responsibility in development, exploration and operations, including Vice President, Exploration and Vice President, Sacramento Basin.  Prior to joining Venoco, Mr. Wracher worked for Mobil Oil Corporation where he was responsible for both development and exploration geology.  Mr. Wracher holds a B.S. in Geology from Fort Lewis College, a M.S. in Geology from San Diego State University and a M.S. in Global Energy Management from the University of Colorado, Denver.

Available Information

We maintain a link to investor relations information on our website, www.venocoinc.com, where we make available, free of charge, Venoco and joint Venoco/DPC filings with the SEC, including annual reports on Form 10‑K, quarterly reports on Form 10‑Q, current reports on Form 8‑K, and all amendments to those reports, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. We also make available on our website copies of our code of business conduct and ethics and certain other governance documents. You may request a printed copy of these materials or any exhibit to this report by writing to the Corporate Secretary, Venoco, Inc., 370 17th Street, Suite 3900, Denver, Colorado, 80202‑1370. You may also read and copy any materials we file with the SEC at the SEC’s Public Reference Room, which is located at 100 F Street, NE, Room 1580, Washington, D.C. 20549. Information regarding the Public Reference Room may be obtained by calling the SEC at 1‑800‑ SEC‑0330. In addition, the SEC maintains a website at www.sec.gov that contains the documents we file with the SEC. Our website, and the information contained on or connected to our website, is not incorporated by reference herein and our web address is included as an inactive textual reference only.

ITEM 1A.  Risk Factors

Risks Related to Bankruptcy

We are subject to risks and uncertainties associated with our Chapter 11 proceedings.

On March 18, 2016, the Company filed voluntary petitions seeking relief under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court.

Our operations and ability to develop and execute our business plan, our financial condition, our liquidity and our continuation as a going concern, are subject to the risks and uncertainties associated with our bankruptcy. These risks include the following:

Delays in our Chapter 11 proceedings increase the risks of our being unable to reorganize our business and emerge from bankruptcy and increase our costs associated with the bankruptcy process.

These risks and uncertainties could affect our business and operations in various ways. For example, negative events or publicity associated with our Chapter 11 proceedings could adversely affect our relationships with our suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect our operations and financial condition. Also, pursuant to the Bankruptcy Code, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond in a timely manner to certain events or take advantage of certain opportunities. We also need Bankruptcy Court confirmation of the Plan. Because of the risks and uncertainties associated with our Chapter 11 proceedings, we cannot accurately predict or quantify the ultimate impact that events that occur during our Chapter 11 proceedings will have on our business, financial condition and results of operations, and there is no certainty as to our ability to continue as a going concern.

We may not be able to obtain confirmation of a Chapter 11 plan of reorganization.

To emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements related to the adequacy of disclosure with respect to a Chapter 11 plan of reorganization, solicit and obtain the requisite acceptances of such a reorganization plan and fulfill other statutory conditions for confirmation of such a plan. The Bankruptcy Court approved the disclosure statement with respect to the Plan on May 16, 2016. While a confirmation hearing on the Plan has been scheduled on July 13, 2016, it is possible that hearing could be delayed. It is also possible that the Bankruptcy Court will not confirm the Plan.

Creditors may not vote in favor of our Plan, and certain parties in interest may file objections to the Plan in an effort to persuade the Bankruptcy Court that we have not satisfied the confirmation requirements under Section 1129 of

the Bankruptcy Code. Even if no objections are filed and the requisite acceptances of our Plan are received from creditors entitled to vote on the Plan, the Bankruptcy Court, which can exercise substantial discretion, may not confirm the Plan. The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims, subordinated or senior claims, or equity interests).

If the Plan is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims.

Even if a Chapter 11 Plan of Reorganization is consummated, we may not be able to achieve our stated goals and continue as a going concern.

Even if the Plan or another Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in demand for our oil and gas and increasing expenses. Accordingly, we cannot guarantee that the Plan or any other Chapter 11 plan of reorganization will achieve our stated goals.

Furthermore, even if our debts are reduced or discharged through the Plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of our Chapter 11 proceedings. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all.

Our ability to continue as a going concern is dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern, even if the Plan is confirmed.

We have substantial liquidity needs and may not be able to obtain sufficient liquidity to confirm a plan of reorganization and exit bankruptcy.

Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with our Chapter 11 proceedings and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 proceedings. While we entered into a Debtor-in-Possession (DIP) Credit Agreement in connection with the Chapter 11 filings, which provides for a multi-draw term loan in an aggregate amount of up to $35.0 million, as of the date hereof, we have not received a commitment for any additional interim financing or exit financing to repay the DIP financing if drawn.

There are no assurances that our current liquidity is sufficient to allow us to satisfy our obligations related to the Chapter 11 proceedings, allow us to proceed with the confirmation of a Chapter 11 plan of reorganization and allow us to emerge from bankruptcy. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs on acceptable terms.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

Upon a showing of cause, the Bankruptcy Court may convert our Chapter 11 case to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in our Plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

We may be subject to claims that will not be discharged in our Chapter 11 proceedings, which could have a material adverse effect on our financial condition and results of operations.

The Bankruptcy Code provides that the confirmation of a Chapter 11 plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization. Any claims not ultimately discharged through a Chapter 11 plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

Our financial results may be volatile and may not reflect historical trends.

During the Chapter 11 proceedings, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and claims assessments may significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the bankruptcy filing.

In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may change materially relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.

The implementation of our Chapter 11 Plan may limit or reduce, and transfers and issuances of our equity otherwise may impair our ability to utilize our federal income tax net operating loss carryforwards and depreciation, depletion and amortization deductions in future years.

Under federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. The Company has net operating loss carryforwards of approximately $558 million as of December 31, 2015. Our ability to utilize our net operating loss carryforwards to offset future taxable income and to reduce federal income tax liability is subject to certain requirements and restrictions. Under our Chapter 11 plan, as a result of excluding cancellation of debt income and being required to reduce certain tax attributes, including our net operating losses and our tax basis in our assets, we anticipate that our ability to carry forward our existing net operating losses will be significantly reduced or eliminated, regardless of whether Section 382 applies.  In addition if we experience an “ownership change,” as defined in Section 382, then our ability to otherwise use our current or future net operating loss carryforwards and amortizable tax basis in our properties, in each case prior to such ownership change, may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an “ownership change” under Section 382 if one or more stockholders owning 5% or more of a corporation’s common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period. Absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its net operating losses that may be utilized to offset future taxable income generally is subject to an annual limitation. Further, future deductions for depreciation, depletion and amortization could be limited if the fair value of our assets is determined to be less than the tax basis.

Risks Related to our Business:

Commodity prices are volatile and change for reasons that are beyond our control. Decreases in the price we receive for our production adversely affect our business, financial condition, results of operations and liquidity.

Declines in the prices we receive for our production adversely affect many aspects of our business, including our financial condition, revenues, profitability, cash flows, results of operations, liquidity, rate of growth, quantity and

present value of our reserves, and the carrying value of our properties, all of which depend primarily or in part upon those prices. For example, due in significant part to lower commodities prices, our revenues from oil and natural gas sales declined 74% in the fourth quarter of 2015 compared to the same period in 2014. Declines in the prices we receive for our oil and natural gas also adversely affect our ability to finance capital expenditures, make acquisitions, raise capital and satisfy our financial obligations. In addition, declines in prices reduce the amount of oil and natural gas that we can produce economically and the estimated value of that production and, as a result, adversely affect our estimated proved reserves. For example, lower commodity prices contributed to a dramatic decline in our proved reserves from December 31, 2014 to December 31, 2015.  Among other things, a reduction in our reserves can limit the capital available to us, as the availability of many sources of capital likely will be based to a significant degree on the estimated quantities and value of those reserves.

Commodity prices are subject to wide fluctuations in response to changes in supply and demand. Prices have historically been volatile and are likely to continue to be volatile in the future. During 2015, the daily Brent oil spot price ranged from a high of $66.77 per Bbl to a low of $36.11 per Bbl and the NYMEX natural gas Henry Hub spot price ranged from a high of $3.23 per MMBtu to a low of $1.76 per MMBtu. The prices of oil and natural gas are affected by a variety of factors that are beyond our control, including changes in global supply and demand for oil and natural gas, domestic and foreign governmental regulations and taxes, geopolitical factors affecting other oil producing countries, the actions of members of the Organization of Petroleum Exporting Countries, or OPEC, the level of global oil and natural gas exploration activity and inventories, the price, availability and consumer acceptance of alternative fuel sources, the availability of refining capacity, technological advances affecting energy consumption, weather conditions, speculative activity, financial and commercial market uncertainty and worldwide economic conditions.

In addition to factors affecting the price of oil and natural gas generally, the prices we receive for our production is affected by factors specific to us and to the local markets where the production occurs. Pricing can be influenced by, among other things, local or regional supply and demand factors (such as refinery or pipeline capacity issues, trade restrictions and governmental regulations) and the terms of our sales contracts.

The prices we receive for our production are also affected by the specific characteristics of the production relative to production sold at benchmark prices. For example, our California oil typically has a lower gravity, and a portion has higher sulfur content, than oil sold at certain benchmark prices. Therefore, because our oil requires more complex refining equipment to convert it into high value products, it may sell at a discount to those prices. This discount, or differential, varies over time and can be affected by factors that do not have the same impact on the price of premium grade light oil. We cannot predict how the differential applicable to our production will change in the future, and it is possible that it will increase. The difficulty involved in predicting the differential also makes it more difficult for us to effectively hedge our production. Many of our hedging arrangements are based on benchmark prices and therefore do not protect us from adverse changes in the differential applicable to our production.

Our planned operations will require additional capital that may not be available.

Our business is capital intensive, and requires substantial expenditures to maintain currently producing wells, to make the acquisitions and/or conduct the exploration, exploitation and development activities necessary to replace our reserves, to pay expenses and to satisfy our other obligations. In recent years, we have chosen to pursue projects that required capital expenditures in excess of cash flow from operations. That fact has made us dependent on external financing to a greater degree than many of our competitors. If we reduce our capital spending in an effort to conserve cash this would likely result in production being lower than anticipated, and could result in reduced revenues, cash flow from operations and income. We have reduced our planned capital expenditures for 2016 relative to 2015, and expect this to result in a decline in production for the year.

DPC is a holding company and is dependent on distributions from Venoco to pay its obligations on its senior notes.

DPC is a holding company with no business operations and no material assets other than the capital stock of Venoco. All of our operations are conducted through Venoco and its subsidiaries. Consequently, DPC is dependent on dividends, distributions, loans or other payments from Venoco to satisfy its obligations.

The ability of Venoco to pay dividends and make other payments to DPC will depend on the cash flows and earnings of Venoco and its subsidiaries, which, in turn, are subject to all of the risks associated with operating in the oil and natural gas industry and as discussed in this section. The ability of DPC’s direct and indirect subsidiaries to pay dividends and make distributions may be restricted by, among other things, applicable laws and regulations and by the terms of the agreements into which they enter.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or the relevant underlying assumptions will materially affect the quantity and present value of our reserves.

The reserve data included in this report represent estimates only. Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various estimates, including estimates based upon assumptions relating to economic factors, such as future commodity prices, production costs, severance and excise taxes and availability of capital, estimates of required capital expenditures and workover and remedial costs, and the assumed effect of governmental regulation. The assumptions underlying our estimates of our proved reserves could prove to be inaccurate, and any significant inaccuracy could materially affect, among other things, future estimates of our reserves, the economically recoverable quantities of oil and natural gas attributable to our properties, the classifications of reserves based on risk of recovery and estimates of our future net cash flows.

Additionally, SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be recorded if they relate to wells scheduled to be drilled within five years after the date of booking. This rule has limited and may in the future limit our ability to record additional proved undeveloped reserves as we pursue our drilling program although we had no proved undeveloped reserves as of December 31, 2015. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five‑year timeframe.

Estimation of proved undeveloped reserves and proved developed non‑producing reserves is almost always based on analogy to existing wells as contrasted with the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Revenues from estimated proved undeveloped reserves and proved developed non‑producing reserves will not be realized until sometime in the future, if at all.

You should not assume that the present values referred to in this report represent the current market value of our estimated oil and natural gas reserves. The actual prices we receive for our production, the timing and success of the production and the expenses related to the development of oil and natural gas properties, each of which is subject to numerous risks and uncertainties, will affect the timing and amount of actual future net cash flows from our proved reserves and their present value. In addition, our PV‑10 estimates are based on assumed future prices and costs. Because market prices for oil at the end of 2015 were significantly lower than the assumed future prices for the year determined under SEC rules, the estimated quantity and present values of our reserves presented in this report are higher than they would be if we had used year‑end oil prices instead. Moreover, the lower year‑end prices may be more reflective of future economic conditions. Further, the effect of derivative instruments is not reflected in these assumed prices. Also, the use of a 10% discount factor to calculate PV‑10 may not necessarily represent the most appropriate discount factor given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

Oil and natural gas exploration, exploitation and development activities may not be successful and could result in a complete loss of a significant investment.

Exploration, exploitation and development activities are subject to many risks. For example, new wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. Similarly, previously producing wells that are returned to production after a period of being shut in may not produce at levels that justify the expenditures made to bring the wells back on line. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry holes but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. Moreover, even commercial wells may be less productive or more expensive than we expect and production from those wells may decline faster than we project. Even when properly used, the seismic data and other technologies we use do not allow us to know conclusively prior to

drilling a well that oil or natural gas is present or that it can be produced economically. In addition, the cost of exploration, exploitation and development activities is subject to numerous uncertainties, and cost factors can adversely affect the economics of a project. Further, our exploration, exploitation and development activities may be curtailed, delayed or canceled as a result of numerous factors, including:

Dry holes and other unsuccessful or uneconomic exploration, exploitation and development activities adversely affect our cash flow, profitability and financial condition, and can adversely affect our reserves.

The marketability of our production is dependent upon gathering systems, transportation facilities and processing facilities that we do not control. When these facilities or systems are unavailable, our operations can be interrupted and our revenues reduced.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems, processing facilities and related infrastructure and services owned by third parties. In general, we do not control these assets or services and our access to them may be limited or denied due to circumstances beyond our control. A significant disruption in the availability of these assets or services could adversely impact our ability to deliver to market the oil and natural gas we produce and thereby cause a significant interruption in our operations.  For example, we have been significantly adversely affected by the rupture and shutdown of the Plains pipeline. In some cases, our ability to deliver to market our oil and natural gas is dependent upon coordination among third parties who own or provide facilities or services we use, and any inability or unwillingness of those parties to coordinate efficiently could also interrupt our operations. These are risks for which we generally do not maintain insurance.

Our hedging arrangements involve credit risk and may limit future revenues from price increases, result in financial losses or reduce our income.

To reduce our exposure to commodity price fluctuations, we enter into hedging arrangements with respect to a portion of our production. See “Quantitative and Qualitative Disclosures About Market Risk” for a summary of our hedging activity. Hedging arrangements expose us to risk of financial loss in some circumstances, including when:

A significant percentage of our cash flow in some prior periods resulted from payments made to us by our hedge counterparties. If hedge counterparties are unable to make payments to us under our hedging arrangements, our results of operation, financial condition and liquidity would be adversely affected. In addition, the uncertainties associated with our hedging programs are greater than those of many of our competitors because the price of the heavy oil that we produce in California is subject to risks that are in addition to the price risk associated with premium grade light oil produced by many of our competitors. Also, our working capital could be impacted if we enter into derivative arrangements that require cash collateral and commodity prices subsequently change in a manner adverse to us. The obligation to post cash or other collateral could, if imposed, adversely affect our liquidity.

Moreover, we have experienced, and may continue to experience, substantial realized and unrealized losses relating to our hedging arrangements. Realized commodity derivative gains or losses represent the difference between the strike prices set forth in hedging contracts settled during the relevant period and the ultimate settlement prices. We incur a realized commodity derivative loss when a contract is settled at a price above the strike price. Losses of this type reflect the limit our hedging arrangements impose on the benefits we would otherwise have received from an increase in the price of oil or natural gas during the period. Unrealized commodity derivative gains and losses represent the change in the fair value of our open derivative contracts from period to period. We incur an unrealized commodity derivative loss when the futures price used to estimate the fair value of a contract at the end of the period rises. We may experience more volatility in our commodity derivative gains and losses than many of our competitors because we do not designate our derivatives as cash flow hedges for accounting purposes and because we hedge a larger percentage of our production than some of our competitors.

We are subject to complex laws and regulations, including environmental laws and regulations, which can adversely affect the cost, manner and feasibility of doing business and limit our growth.

Our operations and facilities are subject to extensive federal, state, and local laws and regulations relating to exploration for, and the exploitation, development, production and transportation of, oil and natural gas, as well as environmental, safety and other matters. Existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations, may harm our business, results of operations and financial condition. Laws and regulations applicable to us include those relating to:

Under these laws and regulations, we could be liable for:

Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities, including suspension or termination of operations. We were, previously, a defendant in a series of lawsuits alleging, among other things, that air, soil and water contamination from the oil and natural gas facility at our Beverly Hills field caused the plaintiffs to develop cancer or other diseases or to sustain related injuries. Similar suits and/or related indemnity claims in the future could have a material adverse effect on our financial condition. Moreover, compliance with applicable laws and regulations could require us to delay, curtail or terminate existing or planned operations.

Some environmental laws and regulations impose strict liability. Strict liability means that in some situations we could be exposed to liability for clean‑up costs and other damages as a result of conduct that was lawful at the time it occurred and without negligence on our part or for the conduct of prior operators of properties we have acquired or other third parties, including, in some circumstances, operators of properties in which we have an interest and parties that provide transportation services for us. Similarly, some environmental laws and regulations impose joint and several liability, meaning that we could be held responsible for more than our share of a particular reclamation or other obligation, and potentially the entire obligation, where other parties were involved in the activity giving rise to the liability. In addition, we may be required to make large and unanticipated capital expenditures to comply with applicable laws and regulations, for example by installing and maintaining pollution control devices. Similarly, our plugging and abandonment obligations will be substantial and may be more than our estimates. Compliance costs are relatively high for us because many of our properties are located offshore California and in other environmentally sensitive areas and because California environmental laws and regulations generally are very strict. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters, but they will be material. Environmental risks generally are not fully insurable.

Changes in applicable laws and regulations could increase our costs, reduce demand for our production, impede our ability to conduct operations or have other adverse effects on our business. In particular, zoning changes related to the processing facility for the South Ellwood field could prohibit continued use of the facility.

Future changes in the laws and regulations to which we are subject may make it more difficult or expensive to conduct our operations and may have other adverse effects on us. Examples of changes in laws and regulations that may affect us adversely include the following:

Zoning.  Venoco’s Ellwood Onshore Facility (“EOF”) is located in the City of Goleta, Santa Barbara County, California. The EOF removes water and gas from crude oil produced from Venoco’s platform Holly before it is transported by pipeline to market. The EOF is a legal non‑conforming use because, in 1991, after the EOF was constructed, the County of Santa Barbara rezoned the property for recreational uses. In January 2015, the Goleta City Council passed an ordinance establishing procedures and guidelines for the termination of nonconforming uses. Under the ordinance, the Goleta City Council could hold a hearing and, after considering certain factors specified in the ordinance, order the termination of the nonconforming use within five years. If so, and if a termination order were entered, Venoco could then apply for a modification of the order to extend the date by which the nonconforming use for the EOF must cease up to an additional 15 years. However, there can be no assurance that such a modification would be granted, or that any legal challenge Venoco might bring regarding the ordinance or its implementation would be successful. If the EOF is terminated, Venoco would have to find an economical alternative to processing crude oil at the EOF or stop producing crude oil from platform Holly. Any alternative processing arrangement would likely entail increased costs, and these costs could be material. Venoco and the City of Goleta have entered into a tolling agreement to give the parties time to gather information and determine whether a negotiated settlement of the dispute is feasible. If Venoco is prevented from using the EOF, this could have a material adverse effect on our production, reserves, cash flows and liquidity.

Greenhouse Gases.  The EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to human health and the environment, which allows EPA to begin regulating GHG emissions under existing provisions of the federal Clean Air Act. EPA is implementing GHG‑related reporting and permitting rules, with which we are complying. Similarly, the U.S. Congress has considered and may in the future consider “cap and trade” legislation that would establish an economy‑wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. On September 27, 2006, California’s governor signed into law Assembly Bill (AB) 32, known as the “California Global Warming Solutions Act of 2006,” which established a statewide cap on GHGs designed to reduce the state’s GHG emissions to 1990 levels by 2020 and establishes a cap and trade program. The California Air Resources Board adopted cap and trade regulations that went into effect on January 1, 2012. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for our production.

On May 12, 2016, the EPA announced its final regulations that set methane emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities as part of an effort to reduce methane emissions from the oil and natural gas sector by 40 to 45 percent from 2012 levels by 2025. Under the rule, oil and gas companies will have to find and repair leaks, capture gas from the completion of fracked wells, limit emissions from new and modified pneumatic pumps, and limit emissions from several types of equipment used at gas transmission compressor stations, including compressors and pneumatic controllers. The California Air Resources Board (“CARB”) also is working on a rulemaking to reduce methane emissions from oil and gas production, processing, storage, and well stimulation (including hydraulic fracturing). CARB has held a series of workshops concerning the draft regulations, which include additional control, monitoring, recordkeeping, and reporting requirements focused on fugitive methane emissions for much of the oil and natural gas industry. In addition, on March 10, 2016, EPA announced that it will begin a formal process under CAA § 111(d) to require companies operating existing oil and gas sources to provide information to assist EPA in developing comprehensive regulations to reduce methane emissions. EPA will send Information Collection Requests (ICRs) to operators to gather information on existing sources of methane emissions, technologies to reduce those emissions, and the costs of those technologies in the production, gathering, processing, and transmission and storage segments of the oil and gas sector.

Hydraulic Fracturing.  We have on occasion in the past engaged in activities involving the use of hydraulic fracturing, and could use hydraulic fracturing in the future. Hydraulic fracturing is a process that creates a fracture extending from the well bore in a rock formation to enable oil or natural gas to move more easily through the rock to a production well. Fractures typically are created through the injection of water and chemicals into the rock formation. Several federal entities, including the EPA, recently have asserted potential regulatory authority over hydraulic fracturing, and the EPA is also conducting a nationwide study into the effects of hydraulic fracturing on drinking water. In June 2015, the EPA released a draft study report for peer review and comment. The draft report did not find evidence of widespread systemic impacts to drinking water, but did find a relatively small number of site-specific impacts. The EPA noted that these results could indicate that such effects are rare or that other limiting factors exist. A final report is expected in 2016. Moreover, in April 2015, the EPA proposed regulations under the CWA to impose pretreatment standards on wastewater discharges associated with hydraulic fracturing activities. Other federal agencies have examined and are continuing to examine hydraulic fracturing, including the U.S. Department of Energy, the U.S. Government Accountability Office and the White House Council for Environmental Quality. Federal agencies have also adopted or are considering additional regulation of hydraulic fracturing. For example, on March 26, 2016, the U.S. Occupational Safety and Health Administration (“OSHA”) issued a final rule, with effective dates of 2018 and 2021 for the hydraulic fracturing industry, which imposes stricter standards for worker exposure to silica, including worker exposure to sand in hydraulic fracturing.

On March 20, 2015 the BLM released a final rule, which is currently stayed pending further litigation, that will regulate hydraulic fracturing on federal and Indian lands. The rule requires operators to: (i) submit detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, the depths of all usable water, estimated volume of fluid to be used, and estimated direction and length of fractures, to the BLM before hydraulically fracturing an existing well; (ii) design and implement a casing and cementing program that follows best practices and meets performance standards to protect and isolate “usable” water; (iii) monitor cementing operations during well construction; (iv) take remedial action if there are indications of inadequate cementing, and demonstrate to the BLM that the remedial action was successful; (v) perform a successful mechanical integrity test prior to the hydraulic fracturing operation; (vi) monitor annulus pressure during a hydraulic fracturing operation; (vii) manage recovered fluids in rigid enclosed, covered or netted and screened above‑ground storage tanks, with very limited exceptions that must be approved on a case‑by‑case basis; (viii) disclose the chemicals used to the BLM and the public, with limited exceptions for material demonstrated to be trade secrets; and (ix) provide documentation of all of the above actions to the BLM. In addition, Congress has considered, and may in the future consider, legislation that would amend the Safe Drinking Water Act to encompass hydraulic fracturing activities. Past proposed legislation would have required hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, including disclosure of chemicals used in the fracturing process, and meet plugging and abandonment requirements. If such legislation is adopted in the future, it would establish an additional level of regulation and impose additional costs on our operations.

Also, some states have adopted, and other states are considering adopting, requirements that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. Some states, municipalities, and other local governmental bodies also have purported to regulate, and in some cases prohibit, hydraulic fracturing activities. For example, Vermont and New York have banned the use of the technology. In addition, various counties and municipalities around the country have passed laws restricting or prohibiting hydraulic fracturing. Our operations currently are not impacted by such laws. However, there is a risk that our operations could be adversely impacted by such laws in the future, especially since our operations are located in California, which historically has been at the forefront of environmental regulation. We will continue to monitor developments in this area.

On September 20, 2013, California enacted Senate Bill 4, which requires the California Department of Conservation, Division of Oil, Gas and Geothermal Resources (“DOGGR”) to promulgate regulations regulating well stimulation operations, including hydraulic fracturing and certain acid stimulation treatments. On December 30, 2014, DOGGR released its final regulations, which go into effect on July 1, 2015. The final regulations require operators to obtain a permit prior to conducting well‑stimulation operations, notify DOGGR prior to the start of well stimulation treatments, and disclose various types of operational data, including the chemical composition of well‑stimulation fluids, which will be made available on a publicly accessible website. Operators also are required to notify every neighboring tenant and landowner within a prescribed distance at least 30 days prior to commencing well‑stimulation operations and

to test well water and surface water suitable for drinking if requested by neighboring landowners. The regulations also require operators to evaluate and test the casing, tubing, certain equipment, and cement lining of the well borehole to ensure that the well’s construction can withstand hydraulic fracturing operations. In addition, operators must ensure that all potentially productive zones, zones capable of over‑pressurizing the surface casing annulus, or corrosive zones are isolated and sealed to prevent vertical migration of gases or fluids behind the casing. The regulations also require operators to monitor and test the well during and after hydraulic fracturing operations to verify that no well failure has occurred. Operators also are required to monitor the California Integrated Seismic Network during and after hydraulic fracturing to determine if any earthquakes of magnitude 2.7 or greater occur within a specified area around the well. If such an earthquake occurs, further hydraulic fracturing in the area is suspended until authorized by DOGGR. Our current operations do not fall within the scope of Senate Bill 4 or the interim or final regulations. However, we will continue to monitor regulatory developments in this area.

As of June 4, 2013, an information gathering rule adopted by the South Coast Air Quality Management District (“SCAQMD”), Rule 1148.2, requires well operators of onshore wells in SCAQMD’s jurisdiction to notify SCAQMD before undertaking certain activities at wells, including hydraulic fracturing, and then to report information regarding chemical usage and operational data regarding those well activities. SCAQMD anticipates reviewing the information gathered under Rule 1148.2 and developing regulations if necessary to protect air quality. If SCAQMD develops regulations regarding well activities, including hydraulic fracturing, our operating costs could increase.

Permitting.  We are obligated to obtain various governmental permits and approvals to pursue our projects, and the relevant permitting and approval processes may change in ways that make them more burdensome, time‑consuming and/or unpredictable. For example, following the Deepwater Horizon well blowout in the Gulf of Mexico, the Secretary of the U.S. Department of the Interior imposed a drilling moratorium in May 2010, which delayed a planned redrill of an inactive well from Platform Gail. That moratorium was subsequently lifted for fixed‑leg platforms like Platform Gail. However, additional moratoria, or similar rules promulgated by other governmental authorities, could have significant impacts on our operations in the future. In addition, the U.S. Department of the Interior has experienced significant delays in processing permit applications for new drilling projects. Delays in the government’s permitting process could have significant impacts on the industry as a whole and our future results of operations.

Derivatives.  The Dodd‑Frank Wall Street Reform and Consumer Protection Act, or the Reform Act, among other things, imposes restrictions on the use and trading of certain derivatives, including energy derivatives. If, as a result of the Reform Act or its implementing regulations, capital or margin requirements or other limitations relating to our commodity derivative activities are imposed, this could have an adverse effect on our ability to implement our hedging strategy. In particular, a requirement to post cash collateral in connection with our derivative positions would likely make it impracticable to implement our current hedging strategy. In addition, capital, margin and business conduct requirements and limitations imposed on our derivative counterparties could increase the costs of pursuing our hedging strategy, in part because there may be fewer counterparties participating in the market and increased counterparty costs that are passed on to us.

Tax.  We could also be adversely affected by future changes to applicable tax laws and regulations. For example, proposals have been made to amend federal and/or California law to impose “windfall profits,” severance or other taxes on oil and natural gas companies. If any of these proposals become law, our costs would increase, possibly materially. Significant financial difficulties currently facing the State of California may increase the likelihood that one or more of these proposals will become law.

President Obama has made proposals that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could defer or eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Our business involves significant operating risks that could adversely affect our production and could be expensive to remedy. We do not have insurance to cover all of the risks that we may face.

Our operations are subject to all the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including:

Our offshore operations are further subject to a variety of operating risks specific to the marine environment, including a dependence on a limited number of gas and water injection wells and electrical transmission lines. Moreover, because we operate in California, we are also susceptible to risks posed by natural disasters such as earthquakes, mudslides, fires and floods.

In addition to lost production and increased costs, these hazards could cause serious injuries, fatalities, contamination or property damage for which we could be held responsible. The potential consequences of these hazards are particularly severe for us because a significant portion of our operations are conducted offshore and in other environmentally sensitive areas, including areas with significant residential populations. We do not maintain insurance in amounts that cover all of the losses to which we may be subject, and the insurance we have may not continue to be available on acceptable terms. Moreover, some risks we face are not insurable. Also, we could in some circumstances have liability for actions taken by third parties over which we have no or limited control, including operators of properties in which we have an interest. The occurrence of an uninsured or underinsured loss could result in significant costs that could have a material adverse effect on our financial condition and liquidity. In addition, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation and development operations to be curtailed while those activities are being completed.

Enhanced recovery techniques may not be successful, which could adversely affect our financial condition or results of operations.

Certain of our properties may provide opportunities for a CO₂ enhanced recovery project, and such a project is currently being pursued at the Hastings Complex by Denbury. Risks associated with enhanced recovery techniques include, but are not limited to, the following:

If any of these risks occur, it could adversely affect the results of the affected project, our financial condition and our results of operations. We may pursue other enhanced recovery activities from time to time as well, and those activities may be subject to the same or similar risks. In addition, as discussed in “Legal Proceedings,” we have been involved in a dispute with Denbury regarding certain aspects of the agreement governing the Hastings Complex project. Any further disputes or disagreements could increase the risks associated with the project or reduce its benefits to us.

A failure to complete successful acquisitions would limit our growth.

Because our oil and natural gas properties are depleting assets, our future reserves, production volumes and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. Acquiring additional oil and natural gas properties, or businesses that own or operate such properties, when attractive opportunities arise is an important component of our strategy. Our focus on the California market reduces the pool of suitable acquisition opportunities. Also, our liquidity and the lack of any market for our common stock may limit our ability to make future acquisitions. If we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. If we are unable to complete suitable acquisitions, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations.

Acquisitions involve a number of risks, including the risk that we will discover unanticipated liabilities or other problems associated with the acquired business or property.

In assessing potential acquisitions, we typically rely to a significant extent on information provided by the seller. We independently review only a portion of that information. In addition, our review of the business or property to be acquired will not be comprehensive enough to uncover all existing or potential problems that could affect us as a result of the acquisition. Accordingly, it is possible that we will discover problems with an acquired business or property that we did not anticipate at the time we completed the transaction. These problems may be material and could include, among other things, unexpected environmental problems, title defects or other liabilities. When we acquire properties on an “as‑is” basis, we have limited or no remedies against the seller with respect to these types of problems.

The success of any acquisition we complete will depend on a variety of factors, including our ability to accurately assess the reserves associated with the acquired properties, future oil and natural gas prices and operating costs, potential environmental and other liabilities and other factors. These assessments are necessarily inexact. As a result, we may not recover the purchase price of a property from the sale of production from the property or recognize an acceptable return from such sales. In addition, we may face greater risks to the extent we acquire properties in areas outside of California, because we may be less familiar with operating, regulatory and other issues specific to those areas.

Our ability to achieve the benefits we expect from an acquisition will also depend on our ability to efficiently integrate the acquired operations with ours. Our management may be required to dedicate significant time and effort to the integration process, which could divert its attention from other business concerns. The challenges involved in the integration process may include retaining key employees and maintaining key employee morale, addressing differences in business cultures, processes and systems and developing internal expertise regarding the acquired properties. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price, and any related increase in interest expense or other related charges.

Competition in the oil and natural gas industry is intense and may adversely affect our results of operations.

We operate in a competitive environment for acquiring properties, marketing oil and natural gas, integrating new technologies and employing skilled personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be willing and able to pay more for oil and natural gas properties than our financial resources permit, and may be able to define, evaluate, bid for and purchase a greater number of properties. Our competitors may also enjoy technological advantages over us and may be able to implement new technologies more rapidly than we can. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future with respect to acquiring prospective reserves, developing reserves, marketing our production, attracting and retaining qualified personnel, implementing new technologies and raising additional capital.

Significant portions of our estimated proved reserves and production are attributable to a small number of wells, and adverse events with respect to one or more of these wells could have a material adverse effect on our business, financial condition and results of operations.

We have a significant portion of our production and reserves concentrated in a relatively few number of wells. As a result of this concentration, any significant adverse events with respect to one or more of these wells, including those discussed elsewhere in this section, could materially and adversely affect our reserves, production, financial condition and results of operations.

Our operations are subject to a variety of contractual, regulatory and other constraints that can limit our production and increase our operating costs and thereby adversely affect our results of operations.

We are subject to a variety of contractual, regulatory and other operating constraints that limit the manner in which we conduct our business. These constraints affect, among other things, the permissible uses of our facilities, the availability of pipeline capacity to transport our production and the manner in which we produce oil and natural gas. These constraints can change to our detriment without our consent. These events, many of which are beyond our control, could have a material adverse effect on our results of operations and financial condition and could reduce estimates of our proved reserves.

The loss of our key personnel could adversely affect our business.

We believe our continued success depends in part on the collective abilities and efforts of our key personnel, including our executive officers. We do not maintain key man life insurance policies. The loss of the services of key management personnel could have a material adverse effect on our results of operations. Additionally, if we are unable to find, hire and retain needed key personnel in the future, our results of operations could be materially and adversely affected.

Shortages of qualified operational personnel or field equipment and services could affect our ability to execute our plans on a timely basis, increase our costs and adversely affect our results of operations.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. From time to time, there have also been shortages of drilling rigs and other field equipment, as demand for rigs and equipment has increased with the number of wells being drilled. These factors can also result in significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. From time to time, we have experienced some difficulty in obtaining drilling rigs, experienced crews and related services and may continue to experience these difficulties in the future. In part, these difficulties arise from the fact that the California market is not as attractive for oil field workers and equipment operators as mid‑continent and Gulf Coast areas where drilling activities are more widespread. If there is a shortage of qualified operational personnel or field equipment and services, our profit margin, cash flow and operating results could be adversely affected and our ability to conduct our operations in accordance with current plans and budgets could be restricted.

Because we cannot control activities on properties we do not operate, we cannot control the timing of those projects. If we are unable to fund required capital expenditures with respect to non‑operated properties, our interests in those properties may be reduced or forfeited.

Other companies operated properties representing 7.2% of our proved reserves as of December 31, 2015. Our ability to exercise influence over operations for these properties and their associated costs is limited. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could prevent the realization of our targeted returns on capital with respect to exploration, exploitation, development or acquisition activities. The success and timing of exploration, exploitation and development activities on properties operated by others depend upon a number of factors that may be outside our control, including:

Where we are not the majority owner or operator of a particular oil and natural gas project, we may have no control over the timing or amount of capital expenditures associated with the project. If we are not willing and able to fund required capital expenditures relating to a project when required by the majority owner or operator, our interests in the project may be reduced or forfeited. Also, we could be responsible for plugging and abandonment and other liabilities in excess of our proportionate interest in the property.

Changes in the financial condition of any of our large oil and natural gas purchasers or other significant counterparties could adversely affect our results of operations and liquidity.

For the year ended December 31, 2015, approximately 97% of our oil and natural gas revenues were generated from sales to two purchasers: Phillips 66 and Tesoro Refining and Marketing Company. A material adverse change in the financial condition of either of our largest purchasers could adversely impact our future revenues and our ability to collect current accounts receivable from such purchasers. We face similar counterparty risks in connection with other contracts under which we may be entitled to receive cash payments, including insurance policies and commodity derivative agreements. Major counterparties may also seek price or other concessions from us if they perceive us to be dependent on them or to lack viable alternatives.

We have been required to write down the carrying value of our properties in the past and may be required to do so again in the future.

We use the full cost method of accounting for oil and natural gas exploitation, development and exploration activities. Under full cost accounting rules, we perform a “ceiling test.” This test is an impairment test and generally establishes a maximum, or “ceiling,” of the book value of our oil and natural gas properties that is equal to the expected after‑tax present value of the future net cash flows from proved reserves, calculated using the twelve month arithmetic average of the first of the month prices. If the net book value of our properties (reduced by any related net deferred income tax liability) exceeds the ceiling, we write down the book value of the properties. For the year ended December 31, 2015, our net capitalized costs exceeded the ceiling by $437.5 million, net of income tax effects, and we recorded an impairment of our oil and gas properties in that amount. We could recognize additional impairments in the future. To the extent our acquisition and development costs increase, we will become more susceptible to ceiling test write downs in low price environments.

All of our producing properties are located in one state and adverse developments in that state would negatively affect our financial condition and results of operations.

Our properties are located primarily in California. Any circumstance or event that negatively impacts the

production or marketing of oil and natural gas in California generally, or in Southern California in particular, would adversely affect our results of operations and cash flows. Many of our competitors have operations that are more geographically dispersed than ours, and therefore may be less subject than we are to risks affecting a particular geographic area.

If the company fails to maintain an effective system of internal controls or discovers material weaknesses in its internal controls over financial reporting, it may not be able to report its financial results accurately or timely or detect fraud, which could have a material adverse effect on its business.

An effective internal control environment is necessary for the company to produce reliable financial reports and is an important part of its effort to prevent financial fraud. The company is required to annually evaluate the effectiveness of the design and operation of its internal controls over financial reporting. Based on these evaluations, the company may conclude that enhancements, modifications, or changes to internal controls are necessary or desirable. While management evaluates the effectiveness of the company's internal controls on a regular basis, these controls may not always be effective. There are inherent limitations on the effectiveness of internal controls, including collusion, management override, and failure in human judgment. In addition, control procedures are designed to reduce rather than eliminate financial statement risk. If the company fails to maintain an effective system of internal controls, or if management or the company's independent registered public accounting firm discovers material weaknesses in the company's internal controls, it may be unable to produce reliable financial reports or prevent fraud, which could have a material adverse effect on the company's business.

ITEM 1B.  Unresolved Staff Comments

None.

ITEM 3.  Legal Proceedings

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.

ITEM 4.  Mine Safety Disclosures.

Not applicable.

PART II

ITEM 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market for Common Stock

There is no market for the common stock of Venoco or DPC. As of May 13, 2016, DPC owns all of the outstanding stock of Venoco, and two affiliates of Mr. Marquez and four affiliated entities own 94% of the outstanding stock of DPC.

Unregistered Sales of Equity Securities

None.

Repurchases of Common Stock

Not applicable.

Dividend Policy

Venoco paid DPC cash dividends of $15.8 million in the third quarter of 2013 and $3.9 million in the first quarter of 2014.  Venoco is currently unable to pay dividends to DPC.

ITEM 6.  Selected Financial Data

The table below contains selected consolidated financial data. The statement of operations, cash flow, balance sheet and other financial data for each year has been derived from our consolidated financial statements. As a result of the going private transaction on October 3, 2012, DPC and Venoco are entities under the common control of Mr. Marquez and his affiliates. The consolidated financial data for DPC prior to 2012 is identical to Venoco. You should read this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and our consolidated financial statements and the related notes included elsewhere in this report. No pro forma adjustments have been made for acquisitions and divestitures of oil and natural gas properties, which will affect the comparability of the data below. Amounts are in thousands.