Exhibit 99.1

DeGolyer and MacNaughton

500 | Spring Valley Road

Suite 800 East

Dallas, Texas 75244

This is a digital representation of a DeGolyer and MacNaughton report.

Each file contained herein is intended to be a manifestation of certain data in the subject report and as such is subject to the definitions, qualifications, explanations, conclusions, and other conditions thereof. The information and data contained in each file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.

DeGolyer and MacNaughton

500 | Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 5, 2016

Venoco, Inc.

Denver Parent Corporation

370 17th Street

Suite 3900

Denver, Colorado 80202

Ladies and Gentlemen:

Pursuant to your request, we have conducted a reserves evaluation of the net proved oil, natural gas liquids (NGL), and gas reserves, as of December 31, 2015, of certain selected properties in which Venoco, Inc. (Venoco) has represented that it owns. Venoco has represented that Denver Parent Corporation (DPC) owns 100 percent of the capital stock of Venoco, and that DPC has no reserves or operations other than through its ownership of Venoco. Accordingly, all statements in this report regarding Venoco's properties and reserves shall also be deemed to apply to DPC. This evaluation was completed on February 5, 2016. The properties evaluated consist of working and royalty interests located in California and Texas. Venoco has represented that these properties account for 100 percent on a net equivalent barrel basis of Venoco's net proved reserves as of December 31, 2015. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4-lO (a) (1}-(32) of Regulation S-X of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Venoco.

Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2015. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Venoco after deducting all interests owned by others.

Estimates of oil, NGL, and gas reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this evaluation were obtained from reviews with Venoco personnel, from Venoco files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Venoco with respect to property interests, 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, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)." The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by Venoco, and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production based on existing economic conditions.

Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as that portion of the total gas to be delivered into a gas pipeline for sale after separation, processing, fuel use, and flare. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit and at the legal pressure base of the state in which the interest is located. Gas quantities included herein are expressed in thousands of cubic feet (McD. Oil reserves estimated herein are those to be recovered by conventional lease separation. NGL reserves are those attributable to the leasehold interests according to processing agreements. Oil and NGL reserves included herein are expressed in terms of barrels (bbl) representing 42 United States gallons per barrel.

Definition of Reserves

Petroleum reserves included in this report are classified as proved.  Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4-lO(a) (1}--(32) of Regulation S-X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment.  In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves - Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible- from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves - Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves - Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence

using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4- 10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

In the preparation of this report, as of December 31, 2015, gross production estimated through December 31, 2015, was deducted from gross ultimate recovery to arrive at the estimates of gross reserves. In some fields this required that the production rates be estimated for up to 2 months, since production data from certain properties were available only through October 2015. Data available from wells drilled through December 31, 2015, were used in this report.

Our estimates of Venoco's net proved reserves attributable to the reviewed properties are based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcD, and thousands of barrels of oil equivalent (Mboe):

Note: Gas is converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1barrel of oil equivalent.

Primary Economic Assumptions

Values shown herein are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating expenses, capital costs, and abandonment costs from the future gross revenue. Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Future income tax expenses were not taken into account in the preparation of these estimates.  Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold.

Revenue values in the report were estimated using the initial prices and expenses provided by Venoco. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following assumptions were used for estimating future prices and costs:

Oil and NGL Prices

An oil and NGL price differential for each property was provided by Venoco. The price for each property was calculated by applying this differential to a posted West Texas Intermediate (WTI) Cushing price of $50.28 per barrel and was held constant for the life of each property. The WTI Cushing oil price of $50.28 per barrel is the 12-month average price, calculated as the unweighted arithmetic average of the first day-of-the-month price for each month within the 12-month period prior to December 31, 2015. The resulting volume weighted average price attributable to the estimated proved reserves was $38.32 per barrel of oil and $32.28 per barrel of NGL.

Gas Prices

A gas price differential for each property was provided by Venoco. The price for each property was calculated by applying this differential to a Henry Hub price of $2.58 per million British thermal units (MMBtu) and was held constant for the life of each property. The Henry Hub gas price of $2.58 per MMBtu is the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to December 31, 2015. British thermal unit factors provided by Venoco were used to convert prices from $/MMBtu to dollars per thousand cubic feet.  The resulting volume-weighted average price attributable to the estimated proved reserves was $2.963 per thousand cubic feet of gas.

Production and Ad Valorem Taxes

Production taxes were calculated using the tax rates for each state in which the reserves are located, including, where appropriate, abatements for enhanced recovery programs. Ad valorem taxes were calculated using rates provided by Venoco based on recent payments.

Operating Expenses, Capital Costs, and Abandonment Costs

Estimates of operating expenses and capital costs, provided by Venoco and based on current costs, were used for the lives of the properties with no increases in the future based on inflation. In certain cases, future costs, either higher or lower than current costs, may have been used because of anticipated changes in operating conditions. Future capital costs were estimated using expected 2016 values and were not adjusted for inflation. Abandonment costs, net of salvage, were provided by Venoco for certain properties and were not adjusted for inflation.

The estimated future revenue to be derived from the production and sale of the net proved reserves, as of December 31, 2015, of the properties evaluated is summarized as follows, expressed in thousands of dollars (M$):

Note:  Future income taxes were not taken into account in the preparation of the estimates of present worth.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant's ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2015, estimated oil and gas reserves.

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, natural gas liquids, and gas

contained in this report has been prepared in accordance with Paragraphs 932-235- 50-4,  932-235-50-6,  932-235-50-7,  932-235-50-9,  932-235-50-30,  and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries -  Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4-lO(a) (1)-(32) of Regulation S-X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S-K of the Securities and Exchange Commission; provided, however, that {i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Venoco or DPC. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Venoco and DPC. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

CERTIFICATE of QUALIFICATION

I, Gregory K Graves, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify: